10-K/A 1 l04079be10vkza.txt TOLEDO EDISON COMPANY 10-K/A SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K/A AMENDMENT NO. 3 (MARK ONE) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO ------------------- -----------------------

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None Indicate by check mark whether the registrant (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 registrant was 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 registrant's 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] Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act): Yes [X] No [ ] State the aggregate market value of the common stock held by non-affiliates of the registrant: None. Indicate the number of shares outstanding of the registrant's classes of common stock, as of the latest practicable date:

EXPLANATORY NOTE The Registrant is filing this Amendment No. 3 to its Annual Report on Form 10-K/A for the year ended December 31, 2002 solely for the purpose of filing a copy of the previously issued report of its independent public accountants, PricewaterhouseCoopers LLP, on the financial statements included in Item 8 thereof. A copy of such report, dated as of August 18, 2003, was inadvertently omitted from the amended and restated version of such Item included in the most recent amendment to that Form 10-K/A filed on September 24, 2003. Although Item 8 is restated herein in its entirety in accordance with applicable SEC regulations, no amendments or changes are reflected therein. FORM 10-K/A TABLE OF CONTENTS

* Indicates the items that have not been revised and are not included in this Form 10-K/A. Reference is made to the original 10-K, as previously amended, for the complete text of such items. PART II THE FOLLOWING ITEM HAS BEEN AMENDED IN THIS AMENDMENT NO. 3: ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 1 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (RESTATED*)

*See Note 1(M). (a) Includes electric sales to associated companies of $232.2 million, $277.9 million and $142.3 million in 2002, 2001 and 2000, respectively. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 2 THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (RESTATED*)

*See Note 1(M). The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. 3 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (RESTATED*)

*See Note 1(M). 4 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (RESTATED*) (CONT'D)

* See Note 1(M). ** Denotes variable rate issue with December 31, 2002 interest rate shown. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 5 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

CONSOLIDATED STATEMENTS OF PREFERRED STOCK

* See Note 1(M) to the Consolidated Financial Statements. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 6 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (RESTATED*)

*See Note 1(M). The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 7 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF TAXES (RESTATED*)

* See Note 1(M). ** Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 8 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include The Toledo Edison Company (Company) and its 90% owned subsidiary, The Toledo Edison Capital Corporation (TECC). The subsidiary was formed in 1997 to make equity investments in a business trust in connection with the financing transactions related to the Bruce Mansfield Plant sale and leaseback (see Note 2). The Cleveland Electric Illuminating Company (CEI), an affiliate, has a 10% interest in TECC. All significant intercompany transactions have been eliminated. The Company is a wholly owned subsidiary of FirstEnergy Corp. FirstEnergy holds directly all of the issued and outstanding common shares of its principal electric utility operating subsidiaries, including, the Company, CEI, Ohio Edison Company (OE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). JCP&L, Met-Ed and Penelec were formerly wholly owned subsidiaries of GPU, Inc. which merged with FirstEnergy on November 7, 2001. The Company follows the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. (A) CONSOLIDATION- The Company consolidates all majority-owned subsidiaries, after eliminating the effects of intercompany transactions. Non-majority owned investments, including investments in limited liability companies, partnerships and joint ventures, are accounted for under the equity method when the Company is able to influence their financial or operating policies. Investments in corporations resulting in voting control of 20% or more are presumed to be equity method investments. Limited partnerships are evaluated in accordance with SEC Staff D-46, "Accounting for Limited Partnership Investments" and American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence. For all remaining investments (excluding those within the scope of SFAS 115), the Company applies the cost method. (B) REVENUES- The Company's principal business is providing electric service to customers in northwestern Ohio. The Company's retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service through the end of the year. Receivables from customers include sales to residential, commercial and industrial customers located in the Company's service area and sales to wholesale customers. There was no material concentration of receivables at December 31, 2002 or 2001, with respect to any particular segment of the Company's customers. The Company and CEI sell substantially all of their retail customers' receivables to Centerior Funding Corporation (CFC), a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a SFAS 140 "qualified special purpose entity") under an asset-backed securitization agreement. Transfers are made in return for an interest in the trust (41% as of December 31, 2002), which is stated at fair value, reflecting adjustments for anticipated credit losses. The average collection period for billed receivables is 28 days. Given the short collection period after billing, the fair value of CFC's interest in the trust approximates the stated value of its retained interest in underlying receivables after adjusting for anticipated credit losses. Accordingly, subsequent measurements of the retained interest under SFAS 115 (as an available-for-sale financial instrument) result in no material change in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated credit losses would not have significantly affected the Company's retained interest in the pool of receivables through the trust. Of the $272 million sold to the trust and outstanding as of December 31, 2002, FirstEnergy had a retained interest in $111 million of the receivables included as other receivables on the Consolidated Balance Sheets. Accordingly, receivables recorded on the Consolidated Balance Sheets were reduced by approximately $161 million due to these sales. Collections of receivables previously transferred to the trust and used for the purchase of new receivables from CFC during 2002, totaled approximately $2.2 billion. The Company processed receivables for the trust and received servicing fees of approximately $1.3 million in 2002. Expenses associated with the factoring discount related to the sale of receivables were $4.7 million in 2002. 9 (C) REGULATORY PLAN- In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. In July 2000, the PUCO approved FirstEnergy's transition plan for the Company, OE and CEI as modified by a settlement agreement with major parties to the transition plan. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation" to the Company's nonnuclear generation business was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $0.8 billion net of deferred income taxes and transition costs related to regulatory assets as filed of $0.5 billion net of deferred income taxes, with recovery through no later than mid-2007 for the Company, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $0.3 billion of impaired generating assets recognized as regulatory assets as described further below, $1.0 billion, net of deferred income taxes, of above-market operating lease costs (see Note 1(M)) and $0.3 billion, net of deferred income taxes, of additional plant costs that were reflected on the Company's regulatory financial statements. Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 160 megawatts (MW) of generation capacity through 2005 at established prices for sales to the Company's retail customers. Customer prices are frozen through the five-year market development period except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Company was authorized increases in annual revenues aggregating approximately $5 million to recover its higher tax costs resulting from the Ohio deregulation legislation. The Company's customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be accomplished by extending the transition cost recovery period. If the customer shopping goals established in the agreement had not been achieved by the end of 2005, the transition cost recovery period could have been shortened for the Company to reduce recovery by as much as $80 million. The Company has achieved its required 20% customer shopping goals in 2002. Accordingly, the Company believes that there will be no regulatory action reducing the recoverable transition costs. The application of SFAS 71 has been discontinued with respect to the Company's generation operations. The SEC issued interpretive guidance regarding asset impairment measurement that concluded any supplemental regulated cash flows such as a competitive transition charge should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance $53 million of impaired plant investments were recognized by the Company as regulatory assets recoverable as transition costs through future regulatory cash flows. Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued, were $559 million as of December 31, 2002. See Note 1(M) for further discussion of the Ohio transition plan. (D) UTILITY PLANT AND DEPRECIATION- Utility plant reflects the original cost of construction (except for the Company's nuclear generating units which were adjusted to fair value in connection with the purchase accounting and impairment tests prepared in connection with the transition plan), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 3.9% in 2002, 3.5% in 2001 and 3.4% in 2000. Annual depreciation expense includes approximately $28.5 million for future decommissioning costs applicable to the Company's ownership interests in three nuclear generating units (Beaver Valley Unit 2, Davis-Besse Unit 1 and Perry Unit 1). The Company's share of the future obligation to decommission these units is approximately $475 million in current dollars and (using a 4.0% escalation rate) approximately $1.0 billion in future dollars. The estimated obligation and 10 the escalation rate were developed based on site specific studies. Payments for decommissioning are expected to begin in 2016, when actual decommissioning work begins. The Company has recovered approximately $192 million for decommissioning through its electric rates from customers through December 31, 2002. The Company has also recognized an estimated liability of approximately $4.8 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy, as required by the Energy Policy Act of 1992. In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. The Company has identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143, asset retirement costs of $123 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $15 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets". No impairment was indicated. The asset retirement liability at the date of adoption will be $172 million. As of December 31, 2002, the Company had recorded decommissioning liabilities of $179.6 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. The cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities will be a $115 million increase to income ($67 million net of tax). The FASB approved SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. Under SFAS 142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill is tested for impairment at least on an annual basis - based on the results of the transition analysis and the 2002 annual analysis, no impairment of the Company's goodwill is required. As described above under "Regulatory Plan" the Company recovers transition costs that represent a significant source of cash. The Company is unable to predict how completion of transition cost recovery will affect future goodwill impairment analyses. Prior to the adoption of SFAS 142, the Company amortized about $14 million of goodwill annually. The goodwill balance as of December 31, 2002 and 2001 was $505 million. The following table shows what net income would have been if goodwill amortization had been excluded from prior periods:

(E) COMMON OWNERSHIP OF GENERATING FACILITIES- The Company, together with CEI and OE and its wholly owned subsidiary, Pennsylvania Power Company (Penn), own and/or lease, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly owned facility in the same proportion as its interest. The Company's portion of operating expenses associated with jointly owned facilities is included in the corresponding operating expenses on the Consolidated Statements of Income. The amounts reflected on the Consolidated Balance Sheet under utility plant at December 31, 2002 include the following: 11

The Bruce Mansfield Plant and Beaver Valley Unit 2 are being leased through sale and leaseback transactions (see Note 2) and the above-related amounts represent construction expenditures subsequent to the transaction. (F) NUCLEAR FUEL- Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Company amortizes the cost of nuclear fuel based on the rate of consumption. (G) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 3B). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date, resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows:

The effects of applying fair value accounting to FirstEnergy's stock options would not materially effect the Company's net income. (H) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. The Company is included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Company recognizing any tax losses or credits it contributed to the consolidated return. (I) RETIREMENT BENEFITS- FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all of the Company's full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. On December 31, 2001, the GPU pension plans were merged with the FirstEnergy plan. The Company uses the projected unit credit method for funding purposes and was not required to make pension contributions during the three years ended December 31, 2002. The assets of the FirstEnergy pension plan consist primarily of common stocks, United States government bonds and corporate bonds. 12 The Company provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company pays insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Company. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. As a result of the reduced market value of FirstEnergy's pension plan assets, it was required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. FirstEnergy's accumulated benefit obligation of $3.438 billion exceeded the fair value of plan assets ($2,889 billion) resulting in a minimum pension liability of $548.6 million. FirstEnergy eliminated its prepaid pension asset of $286.9 million (Company - $18.7 million) and established a minimum liability of $548.6 million (Company - $25.0 million), recording an intangible asset of $78.5 million (Company - $7.6 million) and reducing OCI by $444.2 million (Company - $21.1 million) (recording a related deferred tax asset of $312.8 million (Company - $15.0 million)). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002, increased due to the lower discount rate and asset returns assumed as of December 31, 2002. The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:

13 FirstEnergy's net pension and other postretirement benefit costs for the three years ended December 31, 2002 were computed as follows:

The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. (J) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily CEI, OE, Penn, ATSI, FirstEnergy Solutions Corp. (FES) and FirstEnergy Service Company (FECO). The Ohio transition plan, as discussed in the "Regulatory Plans" section, resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. Unregulated operations under FES now operate the generation businesses of the Company, CEI, OE and Penn. As a result, the Company entered into power supply agreements (PSA) whereby FES purchases all of the Company's nuclear generation and the generation from leased fossil generating facilities and the Company purchases its power from FES to meet its "provider of last resort" obligations. CFC serves as the transferor in connection with the accounts receivable securitization for the Company and CEI. The primary affiliated companies transactions, including the effects of the PSA beginning in 2001, the sale and leaseback of the Company's transmission assets to ATSI in September 2000 and FirstEnergy's providing support services at cost, are as follows:

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from its affiliates, GPU Service, Inc. and FirstEnergy Service Company, both subsidiaries of FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act (PUHCA). The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas; the ratio of each company's amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers and other factors; and specific departmental charge ratios. Management believes that these allocation methods are reasonable. 14 The Company is selling 150 megawatts of its Beaver Valley Unit 2 leased capacity entitlement to CEI. Operating revenues for this transaction were $104.0 million, $97.0 million and $104.0 million in 2002, 2001 and 2000, respectively. This sale is expected to continue through the end of the lease period. (See Note 2.) (K) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. As of December 31, 2002, cash and cash equivalents included $30 million used to redeem long-term debt in January 2003. Noncash financing and investing activities included capital lease transactions amounting to $1.0 million and $36.1 million in 2001 and 2000, respectively. There were no capital lease transactions in 2002. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt and investments other than cash and cash equivalents as of December 31:

The fair value of long-term debt reflects the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Company's ratings. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. The Company has no securities held for trading purposes. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of the Company, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "All other" in the table above) consist of equity securities, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in OCI in accordance with SFAS 115. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized losses were approximately $5.0 million and interest and dividend income totaled approximately $5.9 million. (L) REGULATORY ASSETS- The Company recognizes, as regulatory assets, costs which the FERC and PUCO have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets will continue to be recovered from customers under the Company's transition plan. Based on that plan, the Company continues to bill and collect cost-based rates for its transmission and distribution services, which will remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations. 15 Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:

(M) RESTATEMENTS- The Company is restating its financial statements for the three years ended December 31, 2002. The primary modifications include revisions to reflect a change in the method of amortizing costs being recovered through the Ohio transition plan and recognition of above-market values of certain leased generation facilities. In addition, certain other immaterial previously unrecorded adjustments are now reflected in results for the three years ended December 31, 2002. Transition Cost Amortization - The Company amortizes transition costs, described in Note 1(C) above, using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements, but not in the financial statements prepared under GAAP. TE has revised the amortization schedule under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets the first several years of the transition cost recovery period, compared with the method previously applied. The change in method results in no change in total amortization of the previously recorded regulatory assets recovered under the transition period through the end of 2007. Above-Market Lease Costs - In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior. The merger was accounted for as an acquisition of Centerior, the parent company of TE, under the purchase accounting rules of APB 16. In connection with the reassessment of the accounting for the transition plan, the FirstEnergy reassessed its accounting for the Centerior purchase and determined that above-market lease liabilities should have been recorded at the time of the merger. Accordingly, the Company has restated its financial statements to record additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which TE had previously entered into sale-leaseback arrangements. The Company recorded an increase in goodwill related to the above-market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional consideration would have increased goodwill at the date of the merger. The corresponding impact of the above-market lease liability for the Bruce Mansfield Plant was recorded as a regulatory asset because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided under the Company, Regulatory Plan in effect at the time of the merger and subsequently under the transition plan. The total above-market lease obligation of $111 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017 (approximately $5.7 million annually). The additional goodwill has been recorded effective as of the merger date, and amortization has been recorded through 2001, when goodwill amortization ceased with the adoption of SFAS 142. The total above-market lease obligation of $298 million associated with the Bruce Mansfield Plant is being amortized through the end of 2016 (approximately $18.9 million annually). Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation resulting in no impact to net income. Beginning in 2001, the unamortized regulatory asset has been included in the Company's revised amortization schedule for regulatory assets and amortized through the end of the recovery period in 2007. 16 The Company has reflected the impact of the accounting for the above market lease obligations for the period from the merger in 1997 through 1999 as a cumulative effect adjustment of $4.3 million to retained earnings as of January 1, 2000. The after-tax effect of these items in the years ended December 31, 2002, 2001 and 2000 was as follows:

(1) The provision for depreciation and amortization in 2001 and 2000 includes goodwill amortization of $1.6 million. In addition, the impact of the above market lease obligations increased the following balances in the consolidated balance sheet as of January 1, 2000:

The net impact of the adjustments described above for the next five years is expected to reduce net income in 2003 through 2005 and increase net income in 2006 through 2007. After giving effect to the restatement, total transition cost amortization (including above market leases) is expected to approximate the following for the years from 2003 through 2007 (in millions).

17 Other Unrecorded Adjustments This restatement for the years ended December 31, 2002, 2001 and 2000 also includes adjustments that were not previously recognized that principally related to an adjustment to unbilled revenue in 2001 with a corresponding impact in 2002. The net income impact by year was $7.2 million in 2002, $(7.0) million in 2001 and $(0.8) million in 2000. The effects of all of the changes in this restatement on the previously reported Consolidated Balance Sheet as of December 31, 2002 and 2001, and the Consolidated Statements of Income and Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000 are as follows:

18 CONSOLIDATED STATEMENTS OF CASH FLOWS CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 13,337 $ (5,142) $ 62,911 $ 42,691 $ 137,233 $ 138,144 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 93,482 162,082 130,196 176,796 104,914 106,514 Nuclear fuel and lease amortization 11,866 11,866 22,222 22,222 23,881 23,881 Deferred income taxes, net (5,868) (24,821) 11,897 (1,383) 20,376 22,165 Investment tax credits, net (1,851) (1,851) (3,832) (3,832) (1,827) (1,827) Receivables 13,564 5,164 (9,837) (1,437) (6,671) (6,671) Materials and supplies (5,582) (5,582) 8,336 8,336 4,093 4,093 Accounts payable 42,501 40,801 19,744 22,144 13,997 13,997 Deferred rents and sale/leaseback -- (24,600) -- (24,600) -- (5,700) Other (5,911) (2,379) (51,781) (51,081) (38,180) (36,780) --------- --------- --------- --------- --------- --------- Net cash provided from operating activities $ 155,538 $ 155,538 $ 189,856 $ 189,856 $ 257,816 $ 257,816 ========= ========= ========= ========= ========= ========= CASH FLOWS FROM FINANCING ACTIVITIES $ (29,299) $ (29,299) $ (97,828) $ (97,828) $(179,515) $(179,515) ========= ========= ========= ========= ========= ========= CASH FLOWS FROM INVESTING ACTIVITIES $(105,853) $(105,853) $ (93,111) $ (93,111) $ (77,228) $ (77,228) ========= ========= ========= ========= ========= =========

2. LEASES: The Company leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. The Company and CEI sold their ownership interests in Bruce Mansfield Units 1, 2 and 3 and the Company sold a portion of its ownership interest in Beaver Valley Unit 2. In connection with these sales, which were completed in 1987, the Company and CEI entered into operating leases for lease terms of approximately 30 years as co-lessees. During the terms of the leases, the Company and CEI continue to be responsible, to the extent of their combined ownership and leasehold interest, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company and CEI have the right, at the end of the respective basic lease terms, to renew the leases. The Company and CEI also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. As co-lessee with CEI, the Company is also obligated for CEI's lease payments. If CEI is unable to make its payments under the Bruce Mansfield Plant lease, the Company would be obligated to make such payments. No such payments have been made on behalf of CEI. (CEI's future minimum lease payments as of December 31, 2002 were approximately $0.2 billion, net of trust cash receipts.) Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2002 are summarized as follows:

The future minimum lease payments as of December 31, 2002 are:

19 The Company and CEI refinanced high-cost fixed obligations related to their 1987 sale and leaseback transaction for the Bruce Mansfield Plant through a lower cost transaction in June and July 1997. In a June 1997 offering (Offering), the two companies pledged $720 million aggregate principal amount ($145 million for the Company and $575 million for CEI) of first mortgage bonds due through 2007 to a trust as security for the issuance of a like principal amount of secured notes due through 2007. The obligations of the two companies under these secured notes are joint and several. Using available cash, short-term borrowings and the net proceeds from the Offering, the two companies invested $906.5 million ($337.1 million for the Company and $569.4 million for CEI) in a business trust, in June 1997. The trust used these funds in July 1997 to purchase lease notes and redeem all $873.2 million aggregate principal amount of 10-1/4% and 11-1/8% secured lease obligations bonds (SLOBs) due 2003 and 2016. The SLOBs were issued by a special-purpose funding corporation in 1988 on behalf of lessors in the two companies' 1987 sale and leaseback transaction. The Shippingport Capital Trust arrangement effectively reduces lease costs related to that transaction. 3. CAPITALIZATION: (A) RETAINED EARNINGS- The Company has a provision in its mortgage that requires common stock dividends to be paid out of its total balance of retained earnings. (B) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows:

* FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2002, there were 296,008 stock units outstanding. 20 Stock option activities under the FE Programs for the past three years were as follows:

As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 1G - "Stock-Based Compensation." (C) PREFERRED AND PREFERENCE STOCK- Preferred stock may be redeemed by the Company in whole, or in part, with 30-90 days' notice. The preferred dividend rates on the Company's Series A and Series B shares fluctuate based on prevailing interest rates and market conditions. The dividend rates for both issues averaged 7% in 2002. The Company has five million authorized and unissued shares of $25 par value preference stock. (D) LONG-TERM DEBT- The Company has a first mortgage indenture under which it issues from time to time first mortgage bonds, secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Company. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are:

Included in the table above are amounts for various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. These amounts are $73 million, $54 million and $32 million in 2003, 2004 and 2005, respectively, which represents the next date at which the debt holders may exercise this provision. The Company's obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of 21 credit of $68.0 million and a noncancelable municipal bond insurance policy of $51.1 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letters of credit or policy, the Company is entitled to a credit against its obligation to repay those bonds. The Company pays an annual fee of 1.00% of the amounts of the letters of credit to the issuing bank and is obligated to reimburse the bank for any drawings thereunder. The Company and CEI have unsecured letters of credit of approximately $215.9 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. The Company and CEI are jointly and severally liable for the letters of credit (see Note 2). (E) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with FirstEnergy. As of December 31, 2002, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $21.1 million and unrealized gains of $1.1 million. 4. SHORT-TERM -BORROWINGS: The Company may borrow from its affiliates on a short-term basis. As of December 31, 2002, the Company had total short-term borrowings of $149.7 million from its affiliates. The average interest rate on short-term borrowings outstanding as of December 31, 2002 and 2001, were 1.8% and 3.6%, respectively. 5. COMMITMENTS AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $169 million for property additions and improvements from 2003-2007, of which approximately $54 million is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $34 million, of which approximately $12 million applies to 2003. During the same periods, the Company's nuclear fuel investments are expected to be reduced by approximately $40 million and $19 million, respectively, as the nuclear fuel is consumed. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its ownership and leasehold interests in Beaver Valley Unit 2, the Davis Besse Station and the Perry Plant, the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $77.9 million per incident but not more than $8.8 million in any one year for each incident. The Company is also insured as to its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $263.4 million of insurance coverage for replacement power costs for its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry. Under these policies, the Company can be assessed a maximum of approximately $14.6 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Company's plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs. (C) ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. In accordance with the Ohio transition plan discussed in "Regulatory Plans" in Note 1, generation operations and any related additional capital expenditures for environmental compliance are the responsibility of FirstEnergy's competitive services business unit. 22 The Company is required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Company cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Company believes it is in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Company's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that requires compliance with the NOx budgets at the Company's Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Company's Ohio facilities by May 31, 2004. In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals found constitutional and other defects in the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating ultra-fine particulates but found defects in the new NAAQS rules for ozone and decided that the EPA must revise those rules. The future cost of compliance with these regulations may be substantial and will depend if and how they are ultimately implemented by the states in which the Company operates affected facilities. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. On April 25, 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. The Company has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of December 31, 2002, based on estimates of the total costs of cleanup, the Company's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. The Company has total accrued liabilities aggregating approximately $0.2 million as of December 31, 2002. The effects of compliance on the Company with regard to environmental matters could have a material adverse effect on the Company's earnings and competitive position. These environmental regulations affect the Company's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. The Company believes it is in material compliance with existing regulations but is unable to predict whether environmental regulations will change and what, if any, the effects of such change would be. (D) OTHER LEGAL PROCEEDINGS- Various lawsuits, claims and proceedings related to the Company's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant applicable to the Company are described above. 6. SALE OF GENERATING ASSETS: In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 MW to NRG Energy Inc. The proposed sale had included the 648 MW Bay Shore Plant owned by the Company. On 23 August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves the right to pursue legal action against NRG, its affiliate and its parent, Xcel Energy, for damages, based on the anticipatory breach of the agreement. On February 25, 2003, the U.S. Bankruptcy Court in Minnesota approved FirstEnergy's request for arbitration against NRG. In December 2002, FirstEnergy decided to retain ownership of these plants after reviewing other bids it subsequently received from other parties who had expressed interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, the Company reflected approximately $13 million ($8 million net of tax) of previously unrecognized depreciation and other transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statement of Income. 7. RECENTLY ISSUED ACCOUNTING STANDARDS: FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002 (see Guarantees and Other Assurances). It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (TE's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. TE currently has transactions which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. TE currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. One of these entities TE is currently consolidating is the Shippingport Capital Trust, which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of its interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated parties and a 0.34 percent equity interest by Toledo Edison Capital Corp., a majority owned subsidiary. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and is effective at the beginning of the first interim period beginning after June 15, 2003 (TE's third quarter of 2003) for all other financial instruments. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence in a contract of a general index, such as the Consumer Price Index, would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing 24 contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. FirstEnergy is currently assessing the new guidance and has not yet determined the impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus will be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. TE is currently assessing the new EITF consensus and has not yet determined the impact on its financial position or results of operations following adoption. 8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.

(a) See Note 1(M) for discussion of restated financial data. The changes are principally based on the impact of the revised transition cost amortization and above market rates. In addition, the other adjustments discussed in Note 1(M) increased (decreased) net income for the quarterly periods as follows: (in millions)

25 REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors of The Toledo Edison Company: In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of The Toledo Edison Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiary as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 1(D) to the consolidated financial statements, the Company changed its method of accounting for goodwill in 2002. As discussed in Note 1(M) to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements as of December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002. PricewaterhouseCoopers LLP Cleveland, Ohio August 18, 2003 26 PART IV 3. EXHIBITS - COMMON EXHIBITS TO CEI AND TE EXHIBIT NUMBER 2(a) -- Agreement and Plan of Merger between Ohio Edison and Centerior Energy dated as of September 13, 1996 (Exhibit (2)-1, Form S-4 File No. 333-21011, filed by FirstEnergy). 2(b) -- Merger Agreement by and among Centerior Acquisition Corp., FirstEnergy and Centerior (Exhibit (2)-3, Form S-4 File No. 333-21011, filed by FirstEnergy). 4(a) -- Rights Agreement (Exhibit 4, June 25, 1996 Form 8-K, File Nos. 1-9130, 1-2323 and 1-3583). 4(b)(1) -- Form of Note Indenture between Cleveland Electric, Toledo Edison and The Chase Manhattan Bank, as Trustee dated as of June 13, 1997 (Exhibit 4(c), Form S-4 File No. 333-35931, filed by Cleveland Electric and Toledo Edison). 4(b)(2) -- Form of First Supplemental Note Indenture between Cleveland Electric, Toledo Edison and The Chase Manhattan Bank, as Trustee dated as of June 13, 1997 (Exhibit 4(d), Form S-4 File No. 333-35931, filed by Cleveland Electric and Toledo Edison). 10b(1)(a) -- CAPCO Administration Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members regarding 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 Administration 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 maintenance of transmission facilities to carry out the objectives 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 Agreement, 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 Agreement 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). 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). 27 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 Indenture 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 Indenture 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 between 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, Lessee (Exhibit 4(c), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(3)(b) -- Form of Amendment No. 1 to Facility Lease constituting Exhibit 10d(3)(a) above (Exhibit 4(e), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(4)(a) -- Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the corporate Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees (Exhibit 4(d), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(4)(b) -- Form of Amendment No. 1 to Facility Lease constituting Exhibit 10d(4)(a) above (Exhibit 4(f), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(5)(a) -- Form of Facility Lease 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 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 Fund 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 constituting 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 Owner 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 28 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 constituting Exhibit 10d(7)(a) above (Exhibit 28(d), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(8)(a) -- Form of Participation Agreement dated as of September 30, 1987 among the Owner Participant named therein, the Original Loan Participants listed in Schedule II thereto, as Owner Loan Participants, CTC Mansfield Funding Corporation, 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. 33-0128, 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 between Toledo Edison, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(e), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(10) -- Form of Site Lease dated as of September 30, 1987 between Toledo Edison, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(c), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(11) -- Form of Site Lease dated as of September 30, 1987 between Cleveland Electric, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(d), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(12) -- Form of Amendment No. 1 to the Site Leases constituting Exhibits 10d(10) and 10d(11) above (Exhibit 4(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(13) -- Form of Assignment, Assumption and Further Agreement dated as of September 15, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Cleveland Electric, Duquesne, Ohio Edison, Pennsylvania Power and Toledo Edison (Exhibit 28(f), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(14) -- Form of Additional Support Agreement dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, and Toledo Edison (Exhibit 28(g), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(15) -- Form of Support Agreement dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, 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). 29 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 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). 10d(20)(a) -- Form of Amendment No. 2 to Facility Lease among Citicorp Lescaman, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(a), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10d(20)(b) -- Form of Amendment No. 3 to Facility Lease among Citicorp Lescaman, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(b), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10d(21)(a) -- Form of Amendment No. 2 to Facility Lease among US West Financial Services, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(c), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10d(21)(b) -- Form of Amendment No. 3 to Facility Lease among US West Financial Services, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(d), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10d(22) -- Form of Amendment No. 2 to Facility Lease among Midwest Power Company, Cleveland Electric and Toledo Edison (Exhibit 10(e), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10e(1) -- Centerior Energy Corporation Equity Compensation Plan (Exhibit 99, Form S-8, File No. 33-59635). 3. EXHIBITS - TOLEDO EDISON (TE) EXHIBIT NUMBER 3a -- Amended Articles of Incorporation of TE, as amended effective October 2, 1992 (Exhibit 3a, 1992 Form 10-K, File No. 1-3583). 3b -- Amended and Restated Code of Regulations, dated March 15, 2002. (2001 Form 10-K, Exhibit 3b) (B)4b(1) -- Indenture, dated as of April 1, 1947, between TE 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). 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). 30 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). 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). 4b(47) -- August 1, 1997 (Exhibit 4b(47), 1998 Form 10-K, File No. 1-3583). 4b(48) -- June 1, 1998 (Exhibit 4b (48), 1998 Form 10-K, File No. 1-3583). 4b(49) -- January 15, 2000 (Exhibit 4b(49), 1999 Form 10-K, File No. 1-3583). 4b(50) -- May 1, 2000 (Exhibit 4b(50), 2000 Form 10-K, File No. 1-3583). 4b(51) -- September 1, 2000 4b(52) -- October 1, 2002 12.4 -- Consolidated fixed charge ratios. 13.3 -- TE 2002 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K/A are to be deemed "filed" with the SEC.) 21.3 -- List of Subsidiaries of the Registrant at December 31, 2002. * 31.1 -- Certification of chief executive officer, pursuant to Rule 13a-15(e)/15d-15(e). * 31.2 -- Certification of chief financial officer, pursuant to Rule 13a-15(e)/15d-15(e). * 32 -- Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. * Indicates revised exhibits included in this Form 10-K/A in electronic format. Reference is made to the original 10-K for the other exhibits filed therewith. 31 REPORTS ON FORM 8-K TE TE filed fifteen reports on Form 8-K since September 30, 2002. A report dated October 7, 2002 reported updated cost and schedule estimates associated with efforts to return Davis-Besse Nuclear Power Station to service. A report dated October 31, 2002 reported updated information associated with Davis-Besse restoration efforts. A report dated December 20, 2002 reported that FirstEnergy subsidiaries would retain ownership of four power plants previously planned to be sold. A report dated January 17, 2003 reported updated information related with efforts to prepare Davis-Besse for a safe and reliable return to service. A report dated March 11, 2003 reported updated Davis-Besse information including the installation of the new reactor head on the reactor vessel. A report dated March 17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003 reported updated Davis-Besse information. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003 results and other updated information including Davis-Besse updated ready for restart schedule. A report dated May 9, 2003 reported updated Davis-Besse information. A report dated June 5, 2003 reported updated Davis Besse information. A report dated July 24, 2003, reported updates to the schedule and cost estimates for Davis Besse. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements and restatement and reaudit of 2001 CEI and TE financial statements. A report dated August 7, 2003 reported the pending restatement and reaudit of 2000 CEI and TE financial statements. A report dated September 12, 2003 reported that FE, OE, CEI and TE have received an informal data request from the Securities and Exchange Commission related to the recent restatement of their 2002 financial statements. A report dated October 21, 2003 reported the filing of a proposed rate stabilization plan with the PUCO. 32 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 /s/ Harvey L. Wagner ------------------------------ Harvey L. Wagner Vice President and Controller Chief Accounting Officer Date: November 13, 2003 33

TOLEDO EDISON CO 10-K/A