-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, VOgT5DW0QkOUfKaEK6EmRhXfg+IJzqVGhGIAcTBzXMdGg27p9gIEuAIDffwYvchB 1wzobK6qBBywegNeCE5VdQ== 0000020947-98-000001.txt : 19980317 0000020947-98-000001.hdr.sgml : 19980317 ACCESSION NUMBER: 0000020947-98-000001 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19980213 ITEM INFORMATION: ITEM INFORMATION: FILED AS OF DATE: 19980316 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CLEVELAND ELECTRIC ILLUMINATING CO CENTRAL INDEX KEY: 0000020947 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 340150020 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-02323 FILM NUMBER: 98566599 BUSINESS ADDRESS: STREET 1: 55 PUBLIC SQ STREET 2: PO BOX 5000 CITY: CLEVELAND STATE: OH ZIP: 44101 BUSINESS PHONE: 2166229800 8-K 1 CEI FINANCIALS SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 8-K CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of Report (Date of earliest event reported) February 13, 1998 The Cleveland Electric Illuminating Company (Exact name of Registrant as specified in its charter) Ohio 1-2323 34-0150020 (State or other juris- (Commission (I.R.S. Employer diction of incorporation) File Number) Identification No.) c/o FirstEnergy Corp. 76 South Main Street, Akron, Ohio 44308 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (800)736-3402 Item 5. Other Events Ohio Edison Company reports audited consolidated financial statements for the year ended December 31, 1997 and related matters. Such financial statements and related matters consist of the following: 1) Consolidated Statements of Income 2) Consolidated Balance Sheets 3) Consolidated Statements of Capitalization 4) Consolidated Statements of Retained Earnings 5) Consolidated Statements of Capital Stock and Other Paid-In Capital 6) Consolidated Statements of Cash Flows 7) Consolidated Statements of Taxes 8) Notes to Consolidated Financial Statements 9) Report of Independent Public Accountants 10) Management's Discussion and Analysis of Results of Operations and Financial Condition 11) Consent of Independent Public Accountants Item 7. Exhibits Exhibit Number - ------- 24 Consent of Independent Public Accountants. - 1 - THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME

- 2 - THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS

- 3 - THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont.)

- 5 - THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

- 6 - THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS

- 7 - THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF TAXES

- 8 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include The Cleveland Electric Illuminating Company (Company) and its wholly owned subsidiary, Centerior Funding Corporation (Centerior Funding). The subsidiary was formed in 1995 to serve as the transferor in connection with an accounts receivable securitization completed in 1996. All significant intercompany transactions have been eliminated. The Company is a wholly owned subsidiary of FirstEnergy Corp. (FirstEnergy). Prior to the merger in November 1997 (see Note 2), the Company and The Toledo Edison Company (TE) were the principal operating subsidiaries of Centerior Energy Corporation (Centerior). The merger was accounted for using the purchase method of accounting in accordance with generally accepted accounting principles, and the applicable effects were reflected on the separate financial statements of Centerior's direct subsidiaries as of the merger date. Accordingly, the post-merger financial statements reflect a new basis of accounting, and pre-merger period and post-merger period financial results (separated by a heavy black line) are presented. The Company follows the accounting policies and practices prescribed by The Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with generally accepted accounting principles requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Certain prior year amounts have been reclassified to conform with the current year presentation. REVENUES- The Company's principal business is providing electric service to customers in northeastern 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, 1997 or 1996, with respect to any particular segment of the Company's customers. In May 1996, the Company and TE began to sell on a daily basis substantially all of their retail customer accounts receivable to Centerior Funding under an asset-backed securitization agreement which expires in 2001. In July 1996, Centerior Funding completed a public sale of $150 million of receivables-backed investor certificates in a transaction that qualified for sale accounting treatment. REGULATORY PLAN- FirstEnergy's Rate Reduction and Economic Development Plan for the Company was approved in January 1997, to become effective upon consummation of the merger. The regulatory plan initially maintains current base electric rates for the Company through December 31, 2005. At the end of the regulatory plan period, the Company's base rates will be reduced by $217 - 9 - million (approximately 15 percent below current levels). The regulatory plan also revised the Company's fuel cost recovery method. The Company formerly recovered fuel-related costs not otherwise included in base rates from retail customers through a separate energy rate. In accordance with the regulatory plan, the Company's fuel rate will be frozen through the regulatory plan period, subject to limited periodic adjustments. As part of the regulatory plan, transition rate credits were implemented for customers, which are expected to reduce operating revenues for the Company by approximately $280 million during the regulatory plan period. All of the Company's regulatory assets related to its nonnuclear operations are being recovered under provisions of the regulatory plan (see Regulatory Assets). The Company recognized a fair value purchase accounting adjustment to reduce nuclear plant by $1.71 billion in connection with the FirstEnergy merger (see Note 2); that fair value adjustment recognized for financial reporting purposes will ultimately satisfy the $1.4 billion asset reduction commitment contained in the regulatory plan. For regulatory purposes, the Company will recognize the $1.4 billion of accelerated amortization over the rate plan period. 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 1997), including payroll and related costs such as taxes, employee benefits, administrative and general costs and financing costs (including allowance for funds used during construction). The Company provides for depreciation on a straight- line basis at various rates over the estimated lives of property included in plant in service. In its April 1996 rate order, the PUCO approved depreciation rates for the Company of 2.88% for nuclear property and 3.23 % for nonnuclear property. The annualized composite rate was approximately 2.8% for the post- merger period. Annual depreciation expense includes approximately $11.7 million for future decommissioning costs applicable to the Company's ownership interests in three nuclear generating units. The Company's share of the future obligation to decommission these units is approximately $406 million in current dollars and (using a 3.5% escalation rate) approximately $987 million in future dollars. The estimated obligation and 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 $99 million for decommissioning through its electric rates from customers through December 31, 1997. If the actual costs of decommissioning the units exceed the funds accumulated from investing amounts recovered from customers, the Company expects that additional amount to be recoverable from its customers. The Company has approximately $105.3 million invested in external decommissioning trust funds as of December 31, 1997. Earnings on these funds are reinvested with a corresponding increase to the decommissioning liability. The Company has also recognized an estimated liability of approximately $11.2 million at December 31, 1997 related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992. - 10 - The Financial Accounting Standards Board (FASB) issued a proposed accounting standard for nuclear decommissioning trusts in February 1996. If the standard is adopted as proposed: (1) annual provisions for decommissioning could increase; (2) the net present value of estimated decommissioning costs could be recorded as a liability; and (3) income from the external decommissioning trusts could be reported as investment income. The FASB indicated in October 1997 that it plans to continue work on the proposal in 1998. COMMON OWNERSHIP OF GENERATING FACILITIES- The Company, TE, Duquesne Light Company, Ohio Edison Company (OE) and its wholly owned subsidiary, Pennsylvania Power Company (Penn), constitute the Central Area Power Coordination Group (CAPCO). The CAPCO Companies 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, 1997 include the following: Utility Accumulated Construction Ownership/ Plant Provision for Work in Leasehold Generating Units in Service Depreciation Progress Interest - -------------------------------------------------------------------------- (In millions) Bruce Mansfield Units 1, 2, and 3 $ 62.0 $ 18.1 $ .6 19.92% Beaver Valley Unit 2 342.4 3.5 1.2 24.47% Davis-Besse 200.1 - 3.6 51.38% Perry 521.6 - 3.3 31.11% Eastlake Unit 5 159.9 94.6 .3 68.80% Seneca 64.9 24.3 .1 80.00% - -------------------------------------------------------------------------- Total $1,350.9 $140.5 $ 9.1 ========================================================================== The Bruce Mansfield Plant is being leased through a sale and leaseback transaction (see Note 3) and the above related amounts represent construction expenditures subsequent to the transaction. The Seneca Unit is jointly owned by the Company and a non-CAPCO company. NUCLEAR FUEL- The Company leases its nuclear fuel and pays for the fuel as it is consumed (see Note 3). The Company amortizes the cost of nuclear fuel based on the rate of consumption. The Company's electric rates include amounts for the future disposal of spent nuclear fuel based upon the payments to the DOE. 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 - 11 - 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. Alternative minimum tax credits of $133 million, which may be carried forward indefinitely, are available to reduce future federal income taxes. RETIREMENT BENEFITS- Centerior had sponsored jointly with the Company, TE and Centerior Service Company (Service Company) a noncontributing pension plan (Centerior Pension Plan) which covered all employee groups. Upon retirement, employees receive a monthly pension generally based on the length of service. Under certain circumstances, benefits can begin as early as age 55. The funding policy was to comply with the Employee Retirement Income Security Act of 1974 guidelines. In December 1997, the Centerior Pension Plan was merged into the FirstEnergy pension plans. In connection with the merger, the Company recorded fair value purchase accounting adjustments to recognize the net gain, prior service cost, and net transition asset (obligation) associated with the pension and post retirement benefit plans. The following sets forth the funded status of the former Centerior Pension Plan. The Company's share of the former Centerior Pension Plan's total projected benefit obligation approximates 70% at December 31, 1997. At December 31, 1997 1996 - --------------------------------------------------------------- (In millions) Actuarial present value of benefit | obligations: | Vested benefits $418.9 | $325.8 Nonvested benefits 30.5 | 15.8 - -----------------------------------------------------|-------- Accumulated benefit obligation $449.4 | $341.6 =====================================================|======== Plan assets at fair value $461.9 | $420.8 Actuarial present value of | projected benefit obligation 533.4 | 395.0 - -----------------------------------------------------|-------- Projected benefit obligation in excess of | plan assets 71.5 | (25.8) Unrecognized net gain (loss) (3.0)| 55.0 Unrecognized prior service cost - | (14.2) Unrecognized net transition asset - | 32.3 - -----------------------------------------------------|-------- Net pension liability $ 68.5 | $ 47.3 ============================================================== The assets of the Centerior Pension Plan consisted primarily of investments in common stock, bonds, guaranteed investment contracts, cash equivalent securities and real estate. Net pension costs for the three years ended December 31, 1997 were computed as follows: - 12 -

- 13 - A September 30 measurement date was used for 1996 reporting. The assumed discount rates used in determining the actuarial present value of the projected benefit obligation were 7.25% in 1997, 7.75% in 1996 and 8.0% in 1995. The assumed rate of increase in future compensation levels used to measure this obligation was 4.0% in 1997. The rate of annual compensation increase assumption in 1996 was 3.5% for 1997 and 4.0% thereafter. The rate of annual compensation increase assumption in 1995 was 3.5% for 1996 and 1997 and 4.0% thereafter. Expected long-term rates of return on plan assets were assumed to be 10% in 1997 and 11% in 1996 and 1995. At December 31, 1997, the Company's net pension liability included in Pensions and Other Postretirement Benefits on the Consolidated Balance Sheet was $49.2 million. At December 31, 1996, the Company's net prepaid pension cost included in Deferred Charges -- Other on the Consolidated Balance Sheet was $15.4 million (see Note 2). Centerior had sponsored jointly with its former subsidiaries a postretirement benefit plan which provided all employee groups certain health care, death and other postretirement benefits other than pensions. The plan was contributory, with retiree contributions adjusted annually. The plan was not funded. The accumulated postretirement benefit obligation and accrued postretirement benefit cost for the Centerior postretirement benefit plan are as follows: At December 31, 1997 1996 - -------------------------------------------------------------- (In millions) | Accumulated postretirement benefit | obligation allocation: | Retirees $209.8 | $ 177.1 Fully eligible active plan participants 9.8 | 3.9 Other active plan participants 46.9 | 30.9 - ----------------------------------------------------|--------- Accumulated postretirement benefit | obligation 266.5 | 211.9 Unrecognized transition obligation - | (120.1) Unrecognized net gain - | 44.4 - ----------------------------------------------------|--------- Net postretirement benefit liability $266.5 | $ 136.2 Net periodic postretirement benefit costs for the three years ended December 31, 1997 were computed as follows: - 14 -

- 15 - The Consolidated Balance Sheet classification of Pensions and Other Postretirement Benefits at December 31, 1997 and 1996 includes the Company's share of the accrued postretirement benefit liability of $149.5 million and $72.8 million, respectively (see Note 2). The health care trend rate assumption is approximately 6.0% in the first year gradually decreasing to approximately 4.0% for the year 2008 and later. The discount rates used to compute the accumulated postretirement benefit obligation were 7.25% in 1997, 7.75% in 1996 and 8.0% in 1995. An increase in the health care trend rate assumption by one percentage point in all years would increase the accumulated postretirement benefit obligation by approximately $7.7 million and the aggregate annual service and interest costs by approximately $0.5 million. A September 30 measurement date was used for 1996 reporting. TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and interest charges include amounts for transactions with affiliated companies in the ordinary course of business operations. The Company's transactions with TE and the other FirstEnergy operating subsidiaries (OE and Penn) from the November 8, 1997 merger date are primarily for firm power, interchange power, transmission line rentals and jointly owned power plant operations and construction. (See Note 2.) Beginning in May 1996, Centerior Funding began serving as the transferor in connection with the accounts receivable securitization for the Company and TE. The Service Company (formerly a wholly owned subsidiary of Centerior and now a wholly owned subsidiary of FirstEnergy) provides support services at cost to the Company and other affiliated companies. The Service Company billed the Company $34.1 million, $130.8 million, $148.6 million and $141.1 million in the November 8-December 31, 1997, the January 1-November 7, 1997 period, 1996 and 1995, respectively, for such services. Fuel and purchased power expenses on the Consolidated Statements of Income include the cost of power purchased from TE of $17.7 million, $98.5 million, $105.0 million and $102.1 million in the November 8-December 31, 1997 period, the January 1-November 7, 1997 period, 1996 and 1995, respectively. 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. The Company reflects temporary cash investments at cost, which approximates their market value. Noncash financing and investing activities included capital lease transactions amounting to $16 million, $37 million and $19 million for the years 1997, 1996 and 1995, respectively. All borrowings with initial maturities of less than one year are defined as financial instruments under generally accepted accounting principles 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, - 16 - preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31: 1997 1996 -------------- --------------- Carrying Fair Carrying Fair Value Value Value Value - -------------------------------------------------------------- (In Millions) Long-term debt $3,198 $3,238|$2,562 $2,630 Preferred stock $ 198 $ 198|$ 216 $ 220 Investments other than cash | and cash equivalents: | Debt securities | - (Maturing in more than | 10 years) $ 565 $ 553|$ - $ - Equity securities 10 10| - - All other 105 104| 75 75 - ----------------------------------------------|-------------- $ 680 $ 667|$ 75 $ 75 ============================================================= The carrying values of long-term debt and preferred stock subject to mandatory redemption were adjusted to fair value in connection with the merger and reflect 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 trusts investments. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investments with a corresponding change to the decommissioning liability. In 1996, the Company and TE transferred most of their investment assets in existing trusts into Centerior pooled trust funds for the two companies. The amounts in the table represent the Company's pro rata share of the fair value of such noncash investments. The debt and equity securities referred to above are in the held-to- maturity category. The Company has no securities held for trading purposes. 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 related to nonnuclear operations are being recovered from customers under the Company's regulatory plan. Based on the regulatory plan, at this time, the Company believes it will continue to be able to bill and collect cost-based rates (with the exception of the Company's nuclear operations as discussed below); accordingly, it is appropriate that the Company continue the application of SFAS No. 71, "Accounting for the - 17 - Effects of Certain Types of Regulation" (SFAS 71), in the foreseeable future for its nonnuclear operations. The Company discontinued the application of SFAS 71 for its nuclear operations in October 1997 when implementation of the regulatory plan became probable. The regulatory plan does not provide for full recovery of the Company's nuclear operations. In accordance with SFAS No. 101, "Regulated Enterprises -- Accounting for the Discontinuation of Application of SFAS 71," the Company was required to remove from its balance sheet all regulatory assets and liabilities related to the portion of its business for which SFAS 71 was discontinued and to assess all other assets for impairment. Regulatory assets attributable to nuclear operations of $499.1 million ($324.4 million after taxes) were written off as an extraordinary item in October 1997. The regulatory assets attributable to nuclear operations written off represent the net amounts due from customers for future federal income taxes when the taxes become payable, which, under the regulatory plan, are no longer recoverable from customers. The remainder of the Company's business continues to comply with the provisions of SFAS 71. All remaining regulatory assets of the Company will continue to be recovered through rates set for the nonnuclear portion of its business. For financial reporting purposes, the net book value of the nuclear generating units was not impaired as a result of the regulatory plan. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: At December 31, 1997 1996 - -------------------------------------------------------------- (In millions) Nuclear unit expenses $ 309.0 $ 320.0 Customer receivables for future income taxes 143.0 633.6 Rate stabilization program deferrals 288.1 300.3 Gain from Bruce Mansfield Plant sale* (274.4) - Loss on reacquired debt 80.9 57.8 Other 33.1 38.0 - -------------------------------------------------------------- Total $ 579.7 $1,349.7 =============================================================== * The Gain from the Bruce Mansfield Plant sale was reclassified as a regulatory liability in connection with the purchase accounting adjustments, consistent with the ratemaking treatment. 2. OHIO EDISON-CENTERIOR MERGER: FirstEnergy was formed on November 8, 1997 by the merger of OE and Centerior. FirstEnergy holds directly all of the issued and outstanding common shares of OE and all of the issued and outstanding common shares of Centerior's former direct subsidiaries, which include, among others, the Company and TE. As a result of the merger, the former common shareholders of OE and Centerior now own all of the outstanding shares of FirstEnergy Common Stock. All other classes of capital stock of OE and its subsidiaries and of the subsidiaries of Centerior are unaffected by the Merger and remain outstanding. The merger was accounted for as a purchase of Centerior's net assets with 77,637,704 shares of FirstEnergy Common Stock through the conversion of each outstanding Centerior Common Stock share into 0.525 of a share of FirstEnergy Common Stock (fractional shares were paid in cash). Based on an imputed value of $20.125 per share, the purchase price was approximately - 18 - $1.582 billion which also included approximately $20 million of merger related costs. Goodwill of approximately $2.1 billion was recognized by FirstEnergy (to be amortized on a straight-line basis over forty years), which represented the excess of the purchase price over Centerior's net assets after fair value adjustments. Such amount may be adjusted if additional information produces changed assumptions over the twelve months following the merger as FirstEnergy continues to integrate operations and evaluate options with respect to its generation portfolio. The Company's merger purchase accounting adjustments, which were recorded in the records of Centerior's direct subsidiaries, primarily consist of (1) revaluation of the Company's nuclear generating units to fair value ($1.0 billion), based upon the results of an independent appraisal and estimated discounted future cash flows expected to be generated by its nuclear generating units (the estimated cash flows are based upon management's current view of the likely cost recovery associated with the nuclear units); (2) adjusting by $119 million its preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits (pension liability - $50 million and postretirement obligation - $71 million); (4) recognizing the Company's estimated severance and other compensation liabilities ($56 million); and (5) adjusting the Company's common equity by $272 million. The nuclear assets revaluation does not include decommissioning since that obligation is expected to be recovered with the cash flows provided by the regulated portion of the business. Other assets and liabilities were not adjusted since they remain subject to rate regulation on a historical cost basis. See Note 8. 3. LEASES: The Company leases certain generating facilities, nuclear fuel, certain transmission facilities, office space and other property and equipment under cancelable and noncancelable leases. The Company and TE sold their ownership interests in Bruce Mansfield Units 1, 2 and 3 and TE 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 TE entered into operating leases for lease terms of approximately 30 years as co-lessees. During the terms of the leases, the Company and TE 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 TE have the right, at the end of the respective basic lease terms, to renew the leases. The Company and TE also have the right to purchase the facilities at the expiration of the basic lease term or renewal term (if elected) at a price equal to the fair market value of the facilities. As co-lessee with TE, the Company is also obligated for TE's lease payments. If TE is unable to make its payments under the Beaver Valley Unit 2 and Bruce Mansfield Plant leases, the Company would be obligated to make such payments. No such payments have been made on behalf of TE. (TE's minimum lease payments as of December 31, 1997 were $1.7 billion). - 19 - The Company is buying 150 megawatts of TE's Beaver Valley Unit 2 leased capacity entitlement. Purchased power expense for this transaction was $16.8 million, $87.4 million, $99.4 million and $97.6 million in the November 8-December 31, 1997, the January 1-November 7, 1997 period, 1996 and 1995, respectively. This purchase is expected to continue through the end of the lease period. The future minimum lease payments through 2017 associated with Beaver Valley Unit 2 are approximately $1.2 billion. Nuclear fuel is currently financed for the Company and TE through leases with a special-purpose corporation. As of December 31, 1997, $157 million of nuclear fuel ($93 million for the Company) was financed under a lease financing arrangement totaling $190 million ($90 million of intermediate-term notes and $100 million from bank credit arrangements). The notes mature from 1998 through 2000 and the bank credit arrangements expire in October 1998. Lease rates are based on intermediate-term note rates, bank rates and commercial paper rates. 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, 1997 are summarized as follows: - 20 -

- 21 - The Company and TE 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 ($575 million for the Company and $145 million for TE) of first mortgage bonds due in 2000, 2004 and 2007 to a trust as security for the issuance of a like principal amount of secured notes due in 2000, 2004 and 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 ($569.4 million for the Company and $337.1 million for TE) 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 obligation 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. As noted in the table above, the trust income, which is included in Other Income in the Consolidated Statements of Income, effectively reduce lease costs related to that transaction. 4. CAPITALIZATION: (A) RETAINED EARNINGS- There are no restrictions on retained earnings for payment of cash dividends on the Company's common stock. The merger purchase accounting adjustments included resetting the retained earnings balance at zero at the November 8, 1997 merger date. (B) PREFERRED AND PREFERENCE STOCK- The Company's $42.40 Series T and $88.00 Series R preferred stock are not redeemable before June 1998 and December 2001, respectively, and its $90.00 Series S has no optional redemption provision. All other preferred stock may be redeemed by the Company in whole, or in part, with 30-90 days' notice. The preferred dividend rate on the Company's Series L fluctuates based on prevailing interest rates and market conditions. The dividend rate for this issue was 7% in 1997. Preference stock authorized for the Company is 3,000,000 shares without par value. No preference shares are currently outstanding. (C) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- Annual sinking fund provisions for preferred stock are as follows: - 22 - Redemption Price Per Series Shares Share Date Beginning - ----------------------------------------------- $ 7.35 C 10,000 $ 100 (i) 88.00 E 3,000 1,000 (i) 91.50 Q 10,714 1,000 (i) 90.00 S 18,750 1,000 November 1 1999 88.00 R 50,000 1,000 December 1 2001 - ----------------------------------------------- i) Sinking fund provisions are in effect. Annual sinking fund requirements for the next five years are $14.7 million in 1998, $33.5 million in each year 1999 and 2000, $80.5 million in 2001 and $18.8 million in 2002. A liability of $14 million was included in the Company's net assets as of the merger date for preferred dividends declared attributable to the post-merger period. Accordingly, no accrual for preferred stock dividend requirements is included on the Company's November 8, 1997 to December 31, 1997 Consolidated Statement of Income. (D) LONG-TERM DEBT- The first mortgage indenture and its supplements, which secure all of the Company's first mortgage bonds, serve as direct first mortgage liens on substantially all property and franchises, other than specifically excepted property, owned by the Company. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) - -------------------------------------------------------------- 1998 $ 66.8 1999 145.5 2000 176.0 2001 57.5 2002 229.3 - -------------------------------------------------------------- The Company's obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. One pollution control revenue bond issue is entitled to the benefit of an irrevocable bank letter of credit of $48.1 million. To the extent that drawings are made under this letter of credit to pay principal of, or interest on, the pollution control revenue bonds, the Company is entitled to a credit against its obligation to repay those bonds. The Company pays an annual fee of 1.1% of the amount of the letter of credit to the issuing bank and is obligated to reimburse the bank for any drawings thereunder. The Company and TE have letters of credit of approximately $225 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in June 1999. The letters of credit are secured by first mortgage bonds of the Company and TE in the proportion of 40% and 60%, respectively (see Note 3). - 23 - 5. SHORT-TERM BORROWINGS: FirstEnergy has a $125 million revolving credit facility that expires in May 1998. FirstEnergy and the Service Company may borrow under the facility, with all borrowings jointly and severally guaranteed by the Company and TE. FirstEnergy plans to transfer any of its borrowed funds to the Company and TE. The credit agreement is secured with first mortgage bonds of the Company and TE in the proportion of 40% and 60%, respectively. The credit agreement also provides the participating banks with a subordinate mortgage security interest on the properties of the Company and TE. 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, 1997. Also, the Company may borrow from its affiliates on a short-term basis. At December 31, 1997, the Company had total short-term borrowings of $56.8 million from its affiliates with a weighted average interest rate of approximately 6%. 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES: CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $430 million for property additions and improvements from 1998-2002, of which approximately $105 million is applicable to 1998. Investments for additional nuclear fuel during the 1998-2002 period are estimated to be approximately $172 million, of which approximately $32 million applies to 1998. During the same periods, the Company's nuclear fuel investments are expected to be reduced by approximately $113 million and $42 million, respectively, as the nuclear fuel is consumed. NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $8.92 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its present ownership and leasehold interests in Beaver Valley Unit 2, the Davis-Besse Nuclear Power Station (Davis-Besse) and the Perry Nuclear Power Plant (Perry), the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other CAPCO companies were to contribute their proportionate share of any assessments under the retrospective rating plan) would be $84 million per incident but not more than $10.7 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 $316 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 $13 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. - 24 - 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. GUARANTEE- The Company, together with the other CAPCO companies, has severally guaranteed certain debt and lease obligations in connection with a coal supply contract for the Bruce Mansfield Plant. As of December 31, 1997, the Company's share of the guarantee (which approximates fair market value) was $14.3 million. The price under the coal supply contract, which includes certain minimum payments, has been determined to be sufficient to satisfy the debt and lease obligations. The Company's total payments under the coal supply contract were $51.2 million, $47.0 million and $38.6 million during 1997, 1996 and 1995, respectively. The Company's minimum annual payments are approximately $14 million under the contract, which expires December 31, 1999. ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. The Company has estimated additional capital expenditures for environmental compliance of approximately $12 million, which is included in the construction forecast provided under "Capital Expenditures" for 1998 through 2002. The Company is in compliance with the current sulfur dioxide (SO2) and nitrogen oxides (NOX) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions through the year 1999 will be achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or purchasing emission allowances. Plans for complying with reductions required for the year 2000 and thereafter have not been finalized. The Environmental Protection Agency (EPA) is conducting additional studies which could indicate the need for additional NOX reductions from the Bruce Mansfield Plant by the year 2003. In addition, the EPA is also considering the need for additional NOX reductions from the Company's Ohio facilities. On November 7, 1997, the EPA proposed uniform reductions of NOX emissions across a region of twenty-two states, including Ohio and the District of Columbia (NOX Transport Rule) after determining that such NOX emissions are contributing significantly to ozone pollution in the eastern United States. In a separate but related action, eight states filed petitions with the EPA under Section 126 of the Clean Air Act seeking reductions of NOX emissions which are alleged to contribute to ozone pollution in the eight petitioning states. A December 1997 EPA Memorandum of Agreement proposes to finalize the NOX Transport Rule by September 30, 1998 and establishes a schedule for EPA - 25 - action on the Section 126 petitions. The cost of NOX reductions, if required, may be substantial. The Company continues to evaluate its compliance plans and other compliance options. The Company is required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $25,000 for each day the unit is in violation. The 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 proposed regulations or the interim enforcement policy. The Company is aware of its potential involvement in the cleanup of three hazardous waste disposal sites listed on the Superfund National Priorities List and several other sites. The Company has accrued a liability totaling $4.8 million at December 31, 1997 based on estimates of the costs of cleanup and its proportionate responsibility for such costs. The Company believes that the ultimate outcome of these matters will not have a material adverse effect on the its financial condition, cash flows or results of operations. Legislative, administrative and judicial actions will continue to change the way that the Company must operate in order to comply with environmental laws and regulations. With respect to any such changes and to the environmental matters described above, the Company expects that any resulting additional capital costs which may be required, as well as any required increase in operating costs, would ultimately be recovered from its customers. 7. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 1997 and 1996. - 26 -

EX-24 2 EXHIBIT 24 EXHIBIT 24 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report on the consolidated financial statements of The Cleveland Electric Illuminating Company, dated February 13, 1998 and included in this Form 8-K, into the Company's previously filed Registration Statement, File No. 33-55513. ARTHUR ANDERSEN LLP Cleveland, Ohio March 16, 1998 -----END PRIVACY-ENHANCED MESSAGE-----