EX-13 31 ex13-2ce.txt ANNUAL REPORT - CEI THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 2001 ANNUAL REPORT TO STOCKHOLDERS The Cleveland Electric Illuminating Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the generation, distribution and sale of electric energy in an area of approximately 1,700 square miles in northeastern Ohio. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 1.9 million. Contents Page -------- ---- Selected Financial Data........................................ 1 Management's Discussion and Analysis........................... 2-8 Consolidated Statements of Income.............................. 9 Consolidated Balance Sheets.................................... 10 Consolidated Statements of Capitalization...................... 11-12 Consolidated Statements of Common Stockholder's Equity......... 13 Consolidated Statements of Preferred Stock..................... 13 Consolidated Statements of Cash Flows.......................... 14 Consolidated Statements of Taxes............................... 15 Notes to Consolidated Financial Statements..................... 16-26 Report of Independent Public Accountants....................... 27
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY SELECTED FINANCIAL DATA Nov. 8- Jan. 1- 2001 2000 1999 1998 Dec. 31, 1997 Nov. 7, 1997 ----------------------------------------------------------------------------------------------------------------------- (Dollars in thousands) GENERAL FINANCIAL INFORMATION: | | Operating Revenues.................... $2,076,222 $1,887,039 $1,864,954 $1,795,997 $ 254,892 | $1,537,459 ========== ========== ========== ========== ========== | ========== | Operating Income...................... $ 395,561 $ 390,094 $ 394,766 $ 382,523 $ 50,431 | $ 315,777 ========== ========== ========== ========== ========== | ========== | Income Before Extraordinary Item...... $ 219,044 $ 202,950 $ 194,089 $ 164,891 $ 19,290 | $ 95,191 ========== ========== ========== ========== ========== | ========== | Net Income (Loss)..................... $ 219,044 $ 202,950 $ 194,089 $ 164,891 $ 19,290 | $ (229,247) ========== ========== ========== ========== ========== | ========== | Earnings (Loss) on Common Stock....... $ 193,206 $ 182,107 $ 160,565 $ 140,097 $ 19,290 | $ (274,276) ========== ========== ========== ========== ========== | ========== | Total Assets.......................... $5,856,106 $5,964,631 $6,208,761 $6,318,183 $6,440,284 | ========== ========== ========== ========== ========== | | CAPITALIZATION AT DECEMBER 31: | Common Stockholder's Equity........... $1,082,145 $1,064,839 $ 966,616 $1,008,238 $ 950,904 | Preferred Stock- | Not Subject to Mandatory Redemption 141,475 238,325 238,325 238,325 238,325 | Subject to Mandatory Redemption.... 106,288 26,105 116,246 149,710 183,174 | Long-Term Debt........................ 2,156,322 2,634,692 2,682,795 2,888,202 3,189,590 | ---------- ----------- ---------- ---------- ---------- | Total Capitalization.................. $3,486,230 $3,963,961 $4,003,982 $4,284,475 $4,561,993 | ========== ========== ========== ========== ========== | CAPITALIZATION RATIOS: | Common Stockholder's Equity............ 31.0% 26.9% 24.1% 23.5% 20.9% | Preferred Stock- | Not Subject to Mandatory Redemption. 4.1 6.0 6.0 5.6 5.2 | Subject to Mandatory Redemption..... 3.0 0.6 2.9 3.5 4.0 | Long-Term Debt......................... 61.9 66.5 67.0 67.4 69.9 | ----- ----- ----- ----- ----- | Total Capitalization................... 100.0% 100.0% 100.0% 100.0% 100.0% | ===== ===== ===== ===== ===== | DISTRIBUTION KILOWATT-HOUR | DELIVERIES (Millions): | Residential............................ 5,061 5,061 5,278 4,949 790 | 4,062 Commercial............................. 4,907 6,656 6,509 6,353 893 | 4,990 Industrial............................. 9,593 8,320 8,069 8,024 1,285 | 6,710 Other.................................. 166 167 166 165 89 | 476 ------ ------ ------ ------ ----- | ------ Total ................................. 19,727 20,204 20,022 19,491 3,057 | 16,238 ====== ====== ====== ====== ===== | ====== CUSTOMERS SERVED: | Residential............................ 673,852 667,115 667,954 668,470 671,265 | Commercial............................. 70,636 69,103 69,954 68,896 74,751 | Industrial............................. 4,783 4,851 5,090 5,336 6,515 | Other.................................. 292 307 223 221 278 | ------- ------- ------- ------- ------- | Total.................................. 749,563 741,376 743,221 742,923 752,809 | ======= ======= ======= ======= ======= | | Number of Employees (a)................ 1,025 1,046 1,694 1,798 3,162 | (a) Reduction in 2000 reflects transfer of responsibility for generation operations to FirstEnergy Corp.'s competitive services unit.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Corporate Separation -------------------- Beginning on January 1, 2001, Ohio customers were able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. That legislation required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Also, Ohio utilities that offer both competitive and regulated retail electric services were required to implement a corporate separation plan approved by the Public Utilities Commission of Ohio (PUCO) -- one which provides a clear separation between regulated and competitive operations. In connection with FirstEnergy's transition plan, FirstEnergy separated its businesses into three distinct units -- a competitive services unit, a regulated services unit and a corporate support services unit. We are included in the regulated services unit and continue to deliver power to homes and businesses through our existing distribution system and maintain the "provider of last resort" (PLR) obligation under our rate plan. As a result of the transition plan, FirstEnergy's electric utility operating companies (EUOC) entered into power supply agreements whereby FirstEnergy Solutions Corp. (FES) purchases all of the EUOC nuclear generation, as well as generation from leased fossil generating facilities. FirstEnergy Generation Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil generating units owned by the EUOC. We are a "full requirements" customer of FES to enable us to meet our PLR responsibilities. We continue to provide power directly to wholesale customers under previously negotiated contracts as well as to alternative energy suppliers as part of our market support generation of 400 megawatts (351 megawatts committed as of December 31, 2001). The effect on our reported results of operations during 2001 from FirstEnergy's corporate separation plan and our sale of transmission assets to American Transmission Systems, Inc. (ATSI) in September 2000, are summarized in the following tables: Corporate Restructuring - 2001 Income Statement Effects Increase (Decrease) Corporate Separation ATSI Total ---------- ---- ----- (In millions) Operating Revenues: Power supply agreement with FES...... $334.1 $ -- $334.1 Generating units rent................ 59.1 -- 59.1 Ground lease with ATSI............... -- 2.8 2.8 ----------------------------------------------------------------------------- Total Operating Revenues Effect...... $393.2 $ 2.8 $396.0 ============================================================================= Operating Expenses and Taxes: Fossil fuel costs.................... $(97.6)(a) $ -- $(97.6) Purchased power costs................ 597.4 (b) -- 597.4 Other operating costs................ (90.7)(a) 13.9 (d) (76.8) Provision for depreciation and amortization -- (5.9)(e) (5.9) General taxes........................ (3.2)(c) (9.3)(e) (12.5) Income taxes......................... (4.9) 3.4 (1.5) ----------------------------------------------------------------------------- Total Operating Expenses Effect...... $401.0 $ 2.1 $403.1 ============================================================================= Other Income........................... $ -- $ 4.8 (f) $ 4.8 ============================================================================= (a) Transfer of fossil operations to FGCO. (b) Purchased power from power supply agreement (PSA). (c) Payroll taxes related to employees transferred to FGCO. (d) Transmission services received from ATSI. (e) Depreciation and property taxes related to transmission assets sold to ATSI. (f) Interest on note receivable from ATSI. Results of Operations --------------------- Earnings on common stock in 2001 increased 6.1% to $193.2 million in 2001 from $182.1 million in 2000. Excluding the effects shown in the table above, earnings on common stock increased by 7.4% in 2001 from 2000, being favorably affected by reduced operating expenses and taxes, and lower net interest charges, which were substantially offset by reduced operating revenues. In 2000, earnings on common stock increased 13.4% to $182.1 million from $160.6 million primarily due to higher operating revenues and reduced depreciation and amortization, net interest charges and preferred stock dividend requirements. Excluding the effects shown in the table above, operating revenues decreased by $206.8 million or 11.0% in 2001 from 2000 following a $22.1 million increase in 2000 from the prior year. Customer choice in Ohio and the influence of a declining national economy on our regional business activity combined to lower operating revenues. Electric generation services provided by other suppliers in our service area represented 12.9% of total energy delivered in 2001. Retail generation sales declined in all customer categories, resulting in an overall 14.9% reduction in kilowatt-hour sales from the prior year. As part of Ohio's electric utility restructuring law, the implementation of a 5% reduction in generation charges for residential customers reduced operating revenues by approximately $16.6 million in 2001, compared to 2000. Distribution deliveries declined 2.4% in 2001 from the prior year, reflecting the impact of a weaker economy that contributed to lower commercial and industrial kilowatt-hour sales. Operating revenues were also lower in 2001 from the prior year due to the absence of revenues associated with the low-income payment plan now administered by the Ohio Department of Development; there was also a corresponding reduction in other operating costs associated with that change. Revenues from kilowatt-hour sales to wholesale customers declined $86.7 million in 2001 from last year, with a corresponding 76.4% reduction in kilowatt-hour sales. Additional kilowatt-hour sales to the wholesale market were the largest source of the increase in operating revenues in 2000, compared to the prior year, due in part to additional available generating capacity. Operating revenues from increased kilowatt-hour sales to retail customers were more than offset by a reduction in average retail unit prices in 2000, compared to 1999. While sales to commercial and industrial customers both increased in 2000, sales to residential customers decreased in part due to the cooler summer weather, as compared to the above normal temperatures experienced during 1999. Other electric revenues were also lower in 2000 as a result of the elimination of steam sales and the absence of joint ownership billings to Duquesne Light Company in 2000 resulting from an asset swap with Duquesne in early December 1999. The decline in other revenues was partially offset by additional transmission-related revenues in 2000, compared to the prior year. Changes in KWH Sales 2001 2000 --------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (14.9)% 0.9% Wholesale............................. (76.4)%* 77.6% --------------------------------------------------------------------- Total Electric Generation Sales......... (26.4)% 9.8% ==================================================================== Distribution Deliveries: Residential........................... -- % (4.1)% Commercial and industrial............. (3.2)% 2.7% --------------------------------------------------------------------- Total Distribution Deliveries........... (2.4)% (0.9)% ===================================================================== * Excluding PSA kilowatt-hour sales related to restructuring. Operating Expenses and Taxes Total operating expenses and taxes increased by $183.7 million in 2001 and by $26.8 million in 2000 from the prior year. Excluding the effects of restructuring, total 2001 operating expenses and taxes were $219.4 million lower than the prior year. The following table presents changes from the prior year by expense category excluding the impact of restructuring. Operating Expenses and Taxes - Changes 2001 2000 --------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel and purchased power...................... $(145.6) $ 4.8 Nuclear operating costs....................... (11.8) 12.9 Other operating costs......................... (7.1) 6.7 -------------------------------------------------------------------- Total operation and maintenance expenses.... (164.5) 24.4 Provision for depreciation and amortization... (20.3) (10.3) General taxes................................. (64.8) 10.7 Income taxes.................................. 30.2 2.0 -------------------------------------------------------------------- Total operating expenses and taxes.......... $(219.4) $ 26.8 ==================================================================== The following discussion excludes the effects shown in the preceding table related to the impact of restructuring. The decrease in fuel and purchased power costs in 2001, compared to 2000, reflects the transfer of fossil operations to FGCO, with our power requirements being provided under the PSA. In 2000, fuel and purchased power costs increased a moderate $4.8 million, compared to 1999. The slightly higher costs resulted from a $44.8 million increase in purchased power costs which was significantly offset by a $40.0 million decrease in fuel expense. Most of the increase in purchased power costs occurred in the second quarter as generating unit refueling and maintenance outages reduced internal generation during that period. The reduction in fuel expense in 2000 from the preceding year occurred despite a 3.4% increase in internal generation (due to additional lower-cost nuclear generation), the expiration of an above-market coal contract and continued improvement in coal blending strategies. There was one less nuclear refueling outage in 2001, compared to 2000, resulting in an $11.8 million decrease in nuclear operating costs from the prior year. In 2000, nuclear operating costs increased $12.9 million, compared to 1999, primarily due to additional refueling outage costs and increased ownership of the Perry Plant resulting from the Duquesne asset swap. Other operating costs decreased $7.1 million in 2001 from the prior year reflecting a reduction in low-income payment plan customer costs and the absence of voluntary early retirement costs in 2001, offset in part by additional planned maintenance work at the Bruce Mansfield Plant and the absence in 2001 of gains from the sale of emission allowances. In 2000, other operating costs rose $6.7 million, compared to 1999, with most of the increase resulting from additional leased portable diesel generators and voluntary early retirement costs. Partially offsetting these higher costs were increased gains of $7.8 million realized from the sale of emission allowances in 2000. Depreciation and amortization decreased by $20.3 million in 2001 from the prior year due to new deferrals for shopping incentives under our transition plan. In 2000, as part of the transition plan, generating plant assets were reviewed for possible impairment. Impaired nuclear plant investments were recognized as regulatory assets, for which recovery as transition costs began in January 2001. This reduction in plant investment resulted in a corresponding reduction to depreciation expense beginning in July 2000 and accounted for most of the $10.3 million reduction in depreciation and amortization in 2000 from the preceding year. General taxes decreased by $64.8 million in 2001 from 2000 due to reduced property taxes and other state tax changes in connection with the Ohio electric industry restructuring. The reduction in general taxes was partially offset by $20.1 million of new Ohio franchise taxes in 2001, which are classified as state income taxes on the Consolidated Statements of Income. Higher general taxes in 2000, compared to the prior year, resulted from favorable Ohio and Pennsylvania property tax settlements in 1999. Net Interest Charges Net interest charges continued to trend lower, decreasing by $9.9 million in 2001 and by $10.1 million in 2000, compared to the prior year. We continued to redeem and refinance our outstanding debt and preferred stock during 2001 -- net redemptions and refinancing activities in 2001, totaled $137.0 million and $100.0 million, respectively, and will result in annualized savings of $15.2 million. Preferred Stock Dividend Requirements Preferred stock dividend requirements were $12.7 million lower in 2000, compared to the prior year as a result of preferred stock redemptions and the amortization of fair value adjustments recognized under purchase accounting in 1997. Capital Resources and Liquidity Through net debt and preferred stock redemptions, we continued to reduce the cost of debt and preferred stock, and improve our financial position in 2001. During 2001, we reduced our total debt by approximately $152 million. Our common stockholder's equity as a percentage of total capitalization increased to 31% as of December 31, 2001 from 21% at the end of 1997. We have reduced the average cost of outstanding debt from 8.83% in 1996 to 7.88% in 2001. Following approval of the merger of FirstEnergy and GPU by the New Jersey Board of Public Utilities on September 26, 2001, Standard & Poor's upgraded our credit ratings. Following a period of review and after the Securities and Exchange Commission's approval of the merger on October 29, 2001, Moody's also upgraded our credit ratings. The improved credit ratings result from FirstEnergy's new consolidated credit profile following the merger. Our credit rating outlook from Standard & Poor's and Moody's are stable. The following table summarizes the changes: Credit Ratings Before and After Upgrade Before Upgrade After Upgrade ------------------------------------------------------------------------------- Moody's Moody's Standard Investors Standard Investors & Poor's Service & Poor's Service ------------------------------------------------------------------------------ Corporate/Issuer BB+ Ba1 BBB Baa3 Senior Secured Debt BB+ Baa3 BBB Baa2 Preferred Stock B+ Ba3 BB+ Ba2 ----------------------------------------------------------------------------- We had about $0.7 million of cash and temporary investments and $97.7 million of short-term indebtedness as of December 31, 2001. Under our first mortgage indenture, as of December 31, 2001, we had the capability to issue $476 million of additional first mortgage bonds on the basis of property additions and retired bonds. We have no restrictions on the issuance of preferred stock. Our cash requirements in 2002 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Major contractual obligations for future cash payments are summarized in the following table:
Contractual Obligations --------------------------------------------------------------------------------------------------------- There- 2002 2003 2004 2005 2006 after Total --------------------------------------------------------------------------------------------------------- (In millions) Long-term debt................ $228 $115 $280 $300 $-- $1,584 $2,507 Short-term borrowings......... 98 -- -- -- -- -- 98 Mandatory preferred stock..... 19 1 1 1 1 102 125 Capital leases ............... 1 1 1 1 1 6 11 Operating leases*............. 6 -- 27 19 16 149 217 Unconditional fuel purchases.. 65 36 52 21 -- -- 174 --------------------------------------------------------------------------------------------------------- Total......................... $417 $153 $361 $342 $18 $1,841 $3,132 ========================================================================================================= * Operating lease payments are net of capital trust receipts of $712.8 million (see Note 2).
Our capital spending for the period 2002-2006 is expected to be about $392 million (excluding nuclear fuel) of which approximately $121 million applies to 2002. Investments for additional nuclear fuel during the 2002-2006 period are estimated to be approximately $176 million, of which about $19 million relates to 2002. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $163 million and $32 million, respectively, as the nuclear fuel is consumed. Off balance sheet obligations primarily consist of a sale and leaseback arrangement involving the Bruce Mansfield Plant, which are reflected in the operating lease payments above (see Note 2 - Leases). The present value as of December 31, 2001, of these sale and leaseback operating lease commitments, net of trust investments, total $150 million. We sell substantially all of our retail customer receivables, which provided $97 million of off balance sheet financing as of December 31, 2001. On November 29, 2001, FirstEnergy reached an agreement to sell three of our coal-fired power plants (with an aggregate net book value of $393 million as of December 31, 2001) to NRG Energy Inc. The sale includes our 376 MW Ashtabula, 1,262 MW Eastlake and 249 MW Lakeshore plants. The net, after-tax gain from the sale, based on the difference between the sale price of the plants and their market price used in the Ohio restructuring transition plan, will be credited to customers by reducing the transition cost recovery period. Interest Rate Risk ------------------ Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the table below. We are subject to the inherent risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 2, our investment in the Shippingport Capital Trust effectively reduces future lease obligations, also reducing interest rate risk. Changes in the market value of our nuclear decommissioning trust funds are recognized by making corresponding changes to the decommissioning liability, as described in Note 1 - Utility Plant and Depreciation. The table below presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.
Comparison of Carrying Value to Fair Value ------------------------------------------------------------------------------------------------------------------- There- Fair 2002 2003 2004 2005 2006 after Total Value ------------------------------------------------------------------------------------------------------------------- (Dollars in millions) Investments other than Cash and Cash Equivalents: Fixed Income................. $ 38 $ 48 $ 1 $ 32 $ 31 $ 503 $ 653 $ 674 Average interest rate..... 7.7% 7.6% 7.8% 7.9% 7.7% 7.2% 7.3% ------------------------------------------------------------------------------------------------------------------- Liabilities ------------------------------------------------------------------------------------------------------------------- Long-term Debt: Fixed rate................... $228 $115 $280 $300 $1,396 $2,319 $2,435 Average interest rate .... 7.7% 7.4% 7.7% 9.5% 7.4% 7.7% Variable rate................ $ 188 $ 188 $ 189 Average interest rate..... 2.5% 2.5% Short-term Borrowings........ $ 98 $ 98 $ 98 Average interest rate..... 3.5% 3.5% ------------------------------------------------------------------------------------------------------------------- Preferred Stock.............. $ 19 $ 1 $ 1 $ 1 $ 1 $ 102 $ 125 $ 125 Average dividend rate .... 8.9% 7.4% 7.4% 7.4% 7.4% 9.0% 8.9% -------------------------------------------------------------------------------------------------------------------
Outlook ------- Our industry continues to transition to a more competitive environment. We continue to deliver power to homes and businesses through our existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio, we have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier. Adopting new approaches to regulation and experiencing new forms of competition has created new uncertainties. Regulatory Matters Beginning on January 1, 2001 Ohio customers were able to choose their electricity suppliers. Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of our customers elects to obtain power from an alternative supplier, we reduce the customer's bill with a "generation shopping credit," based on the regulated generation component plus an incentive, and the customer receives a generation charge from the alternative supplier. We have continuing responsibility to provide energy to our franchise customers as the PLR through December 31, 2005. The transition cost portion of rates provides for recovery of certain amounts not otherwise recoverable in a competitive generation market (such as regulatory assets). Transition costs are paid by all customers whether or not they choose an alternative supplier. Under the PUCO-approved transition plan, we assumed the risk of not recovering up to $170 million of transition revenue if the rate of customers (excluding contracts and full-service accounts) switching from our service to an alternative supplier does not reach 20% for any consecutive twelve-month period by December 31, 2005 - the end of the market development period. As of December 31, 2001, the customer-switching rate, on an annualized basis, implies that our risk of not recovering transition revenue has been reduced to approximately $52 million. We are also committed under the transition agreement to make available 400 MW of our generating capacity to marketers, brokers, and aggregators at set prices, to be used for sales only to retail customers in our service area. Through December 31, 2001, approximately 351 MW of the 400 MW supply commitment had been secured by alternative suppliers. We began accepting customer applications for switching to alternative suppliers on December 8, 2000; as of December 31, 2001 we had been notified that over 365,000 of our customers requested generation service from other authorized suppliers, including FES, an affiliated company. Environmental Matters We are in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 5 - Environmental Matters). We continue to evaluate our compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $27,500 for each day a 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. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. 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. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. We have 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. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. We have accrued a liability of $2.9 million as of December 31, 2001, based on estimates of the total costs of cleanup, the proportionate responsibility of other PRPs for such costs and the financial ability of other PRPs to pay. We believe that waste disposal costs will not have a material adverse effect on our financial condition, cash flows, or results of operations. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against FirstEnergy and its subsidiaries. The most significant applicable to us are described above. Significant Accounting Policies ------------------------------- We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect our financial results. All of our assets are subject to their own specific risks and uncertainties and are continually reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Our more significant accounting policies are described below. Regulatory Accounting We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on our costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio, significant amounts of regulatory assets have been recorded -- $874 million as of December 31, 2001. We continually review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. As disclosed in Note 1 - Regulatory Plans, our full recovery of transition costs is dependent on achieving 20% customer shopping levels in any twelve-month period by December 31, 2005. Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet been billed through the end of the year. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Recently Issued Accounting Standards ------------------------------------ The Financial Accounting Standards Board (FASB) approved SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. Under SFAS 142, amortization of existing goodwill will cease January 1, 2002. Instead, goodwill will be tested for impairment at least on an annual basis, and no impairment of goodwill is anticipated as a result of a preliminary analysis. In 2001, we amortized about $38 million of goodwill. In July 2001, the FASB issued Statement of Financial Accounting Standards No. (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. Upon retirement, a gain or loss will be recorded if the cost to settle the retirement obligation differs from the carrying amount. We are currently assessing the new standard and have not yet determined the impact on our financial statements. In September 2001, the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144 supersedes SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The Statement also supersedes the accounting and reporting provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." Our adoption of this Statement, effective January 1, 2002, will result in our accounting for any future impairments or disposals of long-lived assets under the provisions of SFAS 144, but will not change the accounting principles used in previous asset impairments or disposals. Application of SFAS 144 is not anticipated to have a major impact on our accounting for impairments or disposal transactions compared to the prior application of SFAS 121 or APB 30.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2001 2000 1999 -------------------------------------------------------------------------------------------------------------- (In thousands) OPERATING REVENUES.......................................... $2,076,222 $1,887,039 $1,864,954 ---------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel and purchased power................................. 768,306 414,127 409,282 Nuclear operating costs.................................. 139,787 151,571 138,686 Other operating costs.................................... 290,945 374,818 368,103 ---------- ---------- ---------- Total operation and maintenance expenses............... 1,199,038 940,516 916,071 Provision for depreciation and amortization.............. 194,717 220,915 231,225 General taxes............................................ 144,948 222,297 211,636 Income taxes............................................. 141,958 113,217 111,256 ---------- ---------- ---------- Total operating expenses and taxes..................... 1,680,661 1,496,945 1,470,188 ---------- ---------- ---------- OPERATING INCOME............................................ 395,561 390,094 394,766 OTHER INCOME................................................ 13,292 12,568 9,141 ---------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES.......................... 408,853 402,662 403,907 ---------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt............................... 191,695 199,444 211,842 Allowance for borrowed funds used during construction........................................... (2,293) (2,027) (1,755) Other interest expense (credit).......................... 32 2,295 (269) Subsidiary's preferred stock dividend requirements....... 375 -- -- ---------- ---------- ---------- Net interest charges..................................... 189,809 199,712 209,818 ---------- ---------- ---------- NET INCOME.................................................. 219,044 202,950 194,089 PREFERRED STOCK DIVIDEND REQUIREMENTS............................................. 25,838 20,843 33,524 ---------- ---------- ---------- EARNINGS ON COMMON STOCK.................................... $ 193,206 $ 182,107 $ 160,565 ========== ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS As of December 31, 2001 2000 ------------------------------------------------------------------------------------------------------------------ (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $4,071,134 $4,036,590 Less-Accumulated provision for depreciation.................................... 1,725,727 1,624,672 ---------- ---------- 2,345,407 2,411,918 ---------- ---------- Construction work in progress- Electric plant............................................................... 66,266 66,904 Nuclear fuel................................................................. 21,712 24,145 ---------- ---------- 87,978 91,049 ---------- ---------- 2,433,385 2,502,967 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust (Note 2)............................................ 475,543 491,830 Nuclear plant decommissioning trusts........................................... 211,605 189,804 Long-term notes receivable from associated companies........................... 103,425 92,722 Other.......................................................................... 24,611 36,084 ---------- ---------- 815,184 810,440 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 296 2,855 Receivables- Customers.................................................................... 17,706 14,748 Associated companies......................................................... 75,113 81,090 Other (less accumulated provisions of $1,015,000 and $1,000,000, respectively, for uncollectible accounts)...................... 99,716 127,639 Notes receivable from associated companies..................................... 415 384 Materials and supplies, at average cost- Owned........................................................................ 20,230 26,039 Under consignment............................................................ 28,533 38,673 Prepayments and other.......................................................... 31,634 59,377 ---------- ---------- 273,643 350,805 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 874,488 816,143 Goodwill....................................................................... 1,370,639 1,408,869 Property taxes................................................................. 80,470 64,230 Other.......................................................................... 8,297 11,177 ---------- ---------- 2,333,894 2,300,419 ---------- ---------- $5,856,106 $5,964,631 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity.................................................... $1,082,145 $1,064,839 Preferred stock- Not subject to mandatory redemption.......................................... 141,475 238,325 Subject to mandatory redemption.............................................. 6,288 26,105 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures (Note 3)..... 100,000 -- Long-term debt................................................................. 2,156,322 2,634,692 ---------- ---------- 3,486,230 3,963,961 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock........................... 526,630 165,696 Accounts payable- Associated companies......................................................... 81,463 102,915 Other........................................................................ 30,332 54,422 Notes payable to associated companies.......................................... 97,704 28,586 Accrued taxes................................................................. 129,830 178,707 Accrued interest............................................................... 57,101 56,142 Other.......................................................................... 60,664 82,195 ---------- ---------- 983,724 668,663 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes.............................................. 637,339 591,748 Accumulated deferred investment tax credits.................................... 76,187 79,957 Nuclear plant decommissioning costs............................................ 220,798 198,997 Pensions and other postretirement benefits..................................... 231,365 227,528 Other.......................................................................... 220,463 233,777 ---------- ---------- 1,386,152 1,332,007 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 2 and 5)................................................................ ---------- ---------- $5,856,106 $5,964,631 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION As of December 31, 2001 2000 ------------------------------------------------------------------------------------------------------------------------ (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, without par value, authorized 105,000,000 shares 79,590,689 shares outstanding....................................................... $ 931,962 $ 931,962 Retained earnings (Note 3A)........................................................... 150,183 132,877 ---------- ---------- Total common stockholder's equity................................................... 1,082,145 1,064,839 ---------- ---------- Number of Shares Optional Outstanding Redemption Price ---------------- --------------------- 2001 2000 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK (Note 3C): Cumulative, without par value- Authorized 4,000,000 shares Not Subject to Mandatory Redemption: $ 7.40 Series A...................... 500,000 500,000 $101.00 $ 50,500 50,000 50,000 $ 7.56 Series B...................... 450,000 450,000 102.26 46,017 45,071 45,071 Adjustable Series L................... 474,000 474,000 100.00 47,400 46,404 46,404 $42.40 Series T....................... 200,000 200,000 500.00 100,000 96,850 96,850 --------- --------- -------- ---------- ---------- 1,624,000 1,624,000 243,917 238,325 238,325 Redemption Within One Year.............. (96,850) -- --------- --------- -------- ---------- ---------- Total Not Subject to Mandatory Redemption............................ 1,624,000 1,624,000 $243,917 141,475 238,325 ========= ========= ======== ---------- ---------- Subject to Mandatory Redemption:(Note 3D): $ 7.35 Series C...................... 70,000 80,000 101.00 $ 7,070 7,030 8,041 $91.50 Series Q....................... -- 10,716 -- -- -- 10,716 $88.00 Series R....................... -- 50,000 -- -- -- 51,128 $90.00 Series S....................... 17,750 36,500 -- -- 17,268 36,686 --------- --------- -------- ---------- ---------- 87,750 177,216 7,070 24,298 106,571 Redemption Within One Year.............. (18,010) (80,466) --------- --------- -------- ---------- ---------- Total Subject to Mandatory Redemption 87,750 177,216 $ 7,070 6,288 26,105 ========= ========= ======== ---------- ---------- COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES (Note 3E): Cumulative, $25 stated value- Authorized 4,000,000 shares Subject to Mandatory Redemption: 9.00%................................. 4,000,000 -- $ -- 100,000 -- ========= ========= ======== ---------- ---------- LONG-TERM DEBT (Note 3F): First mortgage bonds: 7.625% due 2002................................................................... 195,000 195,000 7.375% due 2003................................................................... 100,000 100,000 9.500% due 2005................................................................... 300,000 300,000 6.860% due 2008................................................................... 125,000 125,000 9.000% due 2023................................................................... 150,000 150,000 ---------- ---------- Total first mortgage bonds...................................................... 870,000 870,000 ---------- ---------- Unsecured notes: * 5.580% due 2033................................................................... 27,700 27,700 ---------- ----------
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd) As of December 31, 2001 2000 ----------------------------------------------------------------------------------------------------------------------- (In thousands) LONG-TERM DEBT (Cont'd): Secured notes: 7.000% due 2002-2009............................................................. 1,790 1,820 7.420% due 2001.................................................................. -- 10,000 8.540% due 2001.................................................................. -- 3,000 8.550% due 2001.................................................................. -- 5,000 8.560% due 2001.................................................................. -- 3,500 8.680% due 2001.................................................................. -- 15,000 9.050% due 2001.................................................................. -- 5,000 9.200% due 2001.................................................................. -- 15,000 7.850% due 2002.................................................................. 5,000 5,000 8.130% due 2002.................................................................. 28,000 28,000 7.750% due 2003.................................................................. 15,000 15,000 7.670% due 2004.................................................................. 280,000 280,000 7.130% due 2007.................................................................. 120,000 120,000 7.430% due 2009.................................................................. 150,000 150,000 8.000% due 2013.................................................................. 78,700 78,700 * 1.986% due 2015.................................................................. 39,835 39,835 7.880% due 2017.................................................................. 300,000 300,000 * 2.115% due 2018.................................................................. 72,795 72,795 * 1.650% due 2020.................................................................. 47,500 47,500 6.000% due 2020.................................................................. 62,560 62,560 6.100% due 2020.................................................................. 70,500 70,500 9.520% due 2021.................................................................. 7,500 7,500 6.850% due 2023.................................................................. 30,000 30,000 8.000% due 2023.................................................................. 46,100 46,100 7.625% due 2025.................................................................. 53,900 53,900 7.700% due 2025.................................................................. 43,800 43,800 7.750% due 2025.................................................................. 45,150 45,150 5.375% due 2028.................................................................. 5,993 5,993 5.350% due 2030.................................................................. 23,255 23,255 4.600% due 2030.................................................................. 81,640 81,640 ---------- ---------- Total secured notes............................................................ 1,609,018 1,665,548 ---------- ---------- Capital lease obligations (Note 2)................................................. 6,740 93,422 ---------- ---------- Net unamortized premium on debt.................................................... 54,634 63,252 ---------- ---------- Long-term debt due within one year................................................. (411,770) (85,230) ---------- ---------- Total long-term debt........................................................... 2,156,322 2,634,692 ---------- ---------- TOTAL CAPITALIZATION.................................................................. $3,486,230 $3,963,961 ========== ========== * Denotes variable rate issue with December 31, 2001 interest rate shown. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Comprehensive Number Carrying Retained Income of Shares Value Earnings ------------- --------- -------- -------- (Dollars in thousands) Balance, January 1, 1999....................... 79,590,689 $931,962 $ 76,276 Net income.................................. $ 194,089 194,089 ========= Cash dividends on preferred stock........... (36,737) Cash dividends on common stock.............. (198,974) ------------------------------------------------------------------------------------------------------------------ Balance, December 31, 1999..................... 79,590,689 931,962 34,654 Net income.................................. $ 202,950 202,950 ========= Cash dividends on preferred stock........... (20,727) Cash dividends on common stock.............. (84,000) ------------------------------------------------------------------------------------------------------------------ Balance, December 31, 2000..................... 79,590,689 931,962 132,877 Net income.................................. $ 219,044 219,044 ========= Cash dividends on preferred stock........... (25,838) Cash dividends on common stock.............. (175,900) ------------------------------------------------------------------------------------------------------------------ < Balance, December 31, 2001..................... 79,590,689 $931,962 $150,183 ==================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemption -------------------- -------------------- Number Carrying Number Carrying of Shares Value of Shares Value --------- -------- --------- -------- (Dollars in thousands) Balance, January 1, 1999............ 1,624,000 $238,325 262,144 $183,174 Redemptions- $ 7.35 Series C................. (10,000) (1,000) $88.00 Series E................. (3,000) (3,000) $91.50 Series Q................. (10,714) (10,714) $90.00 Series S................. (18,750) (18,750) ------------------------------------------------------------------------------------------ Balance, December 31, 1999.......... 1,624,000 238,325 219,680 149,710 Redemptions- $ 7.35 Series C................. (10,000) (1,000) $88.00 Series E................. (3,000) (3,000) $91.50 Series Q................. (10,714) (10,714) $90.00 Series S................. (18,750) (18,750) Amortization of fair market value adjustments- $ 7.35 Series C................. (69) $88.00 Series R................. (3,872) $90.00 Series S................. (5,734) ------------------------------------------------------------------------------------------ Balance, December 31, 2000.......... 1,624,000 238,325 177,216 106,571 Issues 9.00%........................... 4,000,000 100,000 Redemptions- $ 7.35 Series C................. (10,000) (1,000) $88.00 Series R................. (50,000) (50,000) $91.50 Series Q................. (10,716) (10,716) $90.00 Series S................. (18,750) (18,750) Amortization of fair market value adjustments- $ 7.35 Series C................. (11) $88.00 Series R................. (1,128) $90.00 Series S................. (668) ------------------------------------------------------------------------------------------ Balance, December 31, 2001.......... 1,624,000 $238,325 4,087,750 $124,298 ========================================================================================= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------ (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income....................................................... $ 219,044 $ 202,950 $194,089 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization..................... 194,717 220,915 231,225 Nuclear fuel and lease amortization............................. 30,539 37,217 33,912 Other amortization.............................................. (14,071) (11,635) (10,730) Deferred income taxes, net...................................... 46,976 22,373 33,060 Investment tax credits, net..................................... (3,770) (3,617) (3,947) Receivables..................................................... 30,942 (16,875) (31,544) Materials and supplies.......................................... 15,949 (1,697) 18,818 Accounts payable................................................ (45,542) 20,817 26,525 Other........................................................... (109,289) (44,188) (11,283) --------- --------- -------- Net cash provided from operating activities................... 365,495 426,260 480,125 --------- --------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt.................................................. -- -- 26,355 Preferred stock................................................. 96,739 -- -- Short-term borrowings, net...................................... 69,118 -- 22,853 Redemptions and Repayments- Preferred stock................................................. 80,466 33,464 33,464 Long-term debt.................................................. 74,230 212,771 214,405 Short-term borrowings, net...................................... -- 74,885 -- Dividend Payments- Common stock.................................................... 175,900 84,000 198,974 Preferred stock................................................. 27,645 30,518 33,524 --------- --------- -------- Net cash used for financing activities........................ 192,384 435,638 431,159 --------- --------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions................................................... 154,927 96,236 122,194 Loans to associated companies........................................ 11,117 93,106 -- Loan payments from associated companies.............................. (383) -- (53,509) Capital trust investments............................................ (16,287) (25,426) (25,905) Sale of assets to associated companies............................... (11,117) (197,902) -- Other................................................................ 37,413 22,129 25,336 --------- --------- -------- Net cash used for (provided from) investing activities........ 175,670 (11,857) 68,116 --------- --------- -------- Net increase (decrease) in cash and cash equivalents................. (2,559) 2,479 (19,150) Cash and cash equivalents at beginning of year....................... 2,855 376 19,526 --------- --------- -------- Cash and cash equivalents at end of year............................. $ 296 $ 2,855 $ 376 ========= ========= ======== SUPPLEMENTAL CASH FLOWS INFORMATION: Cash Paid During the Year- Interest (net of amounts capitalized)........................... $ 196,001 $ 208,085 $221,360 ========= ========= ======== Income taxes.................................................... $ 131,801 $ 109,212 $ 92,555 ========= ========= ======== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF TAXES For the Years Ended December 31, 2001 2000 1999 ---------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: Real and personal property......................................... $ 72,665 $131,331 $120,725 State gross receipts............................................... 27,169 79,709 78,197 Ohio kilowatt-hour excise.......................................... 42,608 -- -- Social security and unemployment................................... 2,752 11,464 10,941 Other.............................................................. (246) (207) 1,773 --------- -------- -------- Total general taxes......................................... $ 144,948 $222,297 $211,636 ========= ======== ======== PROVISION FOR INCOME TAXES: Currently payable- Federal......................................................... $ 97,675 $106,986 $ 92,627 State........................................................... 17,767 959 2,129 --------- -------- -------- 115,442 107,945 94,756 --------- -------- -------- Deferred, net- Federal......................................................... 42,566 23,265 33,369 State........................................................... 4,410 (892) (309) --------- -------- -------- 46,976 22,373 33,060 --------- -------- -------- Investment tax credit amortization................................. (3,770) (3,617) (3,947) --------- -------- -------- Total provision for income taxes............................ $ 158,648 $126,701 $123,869 ========= ======== ======== INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating income................................................... $ 141,958 $113,217 $111,256 Other income....................................................... 16,690 13,484 12,613 --------- -------- -------- Total provision for income taxes............................ $ 158,648 $126,701 $123,869 ========= ======== ======== RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes...................... $ 377,692 $329,651 $317,958 ========= ======== ======== Federal income tax expense at statutory rate....................... $ 132,192 $115,378 $111,285 Increases (reductions) in taxes resulting from- State income taxes, net of federal income tax benefit........... 14,415 44 1,183 Amortization of investment tax credits.......................... (3,770) (3,617) (3,947) Amortization of tax regulatory assets........................... 766 693 693 Amortization of goodwill........................................ 13,380 13,359 13,282 Other, net...................................................... 1,665 844 1,373 --------- -------- -------- Total provision for income taxes............................ $ 158,648 $126,701 $123,869 ========= ======== ======== ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences......................................... $ 463,344 $495,588 $663,294 Competitive transition charge...................................... 279,198 133,248 21,397 Unamortized investment tax credits................................. (29,528) (35,341) (38,172) Unused alternative minimum tax credits............................. -- (27,115) (71,130) Deferred gain for asset sale to affiliated company................. 49,735 46,583 -- Other.............................................................. (125,410) (21,215) (7,911) --------- -------- -------- Net deferred income tax liability........................... $ 637,339 $591,748 $567,478 ========= ======== ======== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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 subsidiaries, Centerior Funding Corporation (CFC) and Centerior Financing Trust (CFT). 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, Ohio Edison Company (OE), The Toledo Edison Company (TE), 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 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 disclosure of contingent assets and liabilities. Actual results could differ from these estimates. 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, 2001 or 2000, with respect to any particular segment of the Company's customers. The Company and TE sell substantially all of their retail customer receivables to CFC. CFC subsequently transfers the receivables to a trust under an asset-backed securitization agreement. The trust completed private sales of $50 million and $150 million of receivables-backed investor certificates in 2000 and 2001 respectively, in transactions that qualified for sale accounting treatment. CFC's creditors are entitled to be satisfied first out of the proceeds of CFC's assets. The 2001 private sale was used to repay a 1996 public sale of $150 million of receivables-backed investor certificates which was replaced under an amended securitization agreement. FirstEnergy's retained interest in the pool of receivables held by the trust (34% as of December 31, 2001) is stated at fair value reflecting adjustments for anticipated credit losses. Sensitivity analyses reflecting a 10% and 20% increase in the rate of anticipated credit losses did not significantly affect FirstEnergy's retained interest in the pool of receivables. Collections from receivables previously transferred to the trust were used for the purchase of new receivables from CFC during 2001 and totaled approximately $2.2 billion. As of December 31, 2001, receivables recorded on the Consolidated Balance Sheets were reduced by approximately $97 million due to the sale of $185 million of receivables to the trust less the Company's retained interest of $88 million. The Company and TE processed receivables for the trust and received servicing fees of approximately $4.5 million ($3.0 million applicable to the Company) in 2001. Expenses associated with the factoring discount related to the sale of receivables were $12 million in 2001. REGULATORY PLAN- Ohio's 1999 electric utility restructuring law allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, provided for a five percent reduction on the generation portion of residential customers' bills and the opportunity for utilities to recover transition costs, including regulatory assets. Under this law, the PUCO approved FirstEnergy's transition plan in 2000 as modified by a settlement agreement with major parties to the transition plan, which it filed on behalf of the Company, OE and TE. The settlement agreement included approval for recovery of the amounts of transition costs filed in the transition plan through no later than 2008 for the Company, except where a longer period of recovery is provided for in the settlement agreement. The settlement also granted preferred access over FirstEnergy's subsidiaries to nonaffiliated marketers, brokers and aggregators to 400 megawatts of generation capacity through 2005 at established prices for sales to the Company's retail customers. The Company's base electric rates for distribution service under its prior regulatory plan was extended from December 31, 2005 through December 31, 2007. The transition rate credits for customers under its prior regulatory plan was also extended through the Company's transition cost recovery period. The transition plan itemized, or unbundled, the current price of electricity into its component elements -- including generation, transmission, distribution and transition charges. As required by the PUCO's rules, FirstEnergy's transition plan also resulted in the corporate separation of its regulated and unregulated operations, operational and technical support changes needed to accommodate customer choice, an education program to inform customers of their options under the law, and planned changes in how FirstEnergy's transmission system will be operated to ensure access to all users. Customer prices are frozen through a five-year market development period (2001-2005), except for certain limited statutory exceptions including a 5% reduction in the price of generation for residential customers. The Company's customers electing alternative suppliers receive an additional incentive applied to the shopping credit of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive serves to reduce the amortization of transition costs during the market development period and will be recovered through the extension of the transition cost recovery period. If the customer shopping goals established in the agreement are not achieved by the end of 2005, the transition cost recovery period could be shortened for the Company to reduce recovery by as much as $170 million, but any such adjustment would be computed on a class-by-class and pro-rata basis. Based on annualized shopping levels as of December 31, 2001, the Company believes that the maximum potential recovery reduction was approximately $52 million. The application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), to the Company's nonnuclear generation business was discontinued with the issuance of the PUCO transition plan order. The Securities and Exchange Commission (SEC) issued interpretive guidance regarding asset impairment measurement concluding that 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 $304 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 $1.425 billion as of December 31, 2001. All of the Company's regulatory assets are expected to continue to be recovered under provisions of the Ohio transition plan. 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), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs. 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 3.2% in 2001 and 3.4% in 2000 and 1999. Annual depreciation expense includes approximately $29.0 million for future decommissioning costs applicable to the Company's ownership interests in three nuclear generating units. The 2001 amounts reflected an increase of approximately $17 million from implementing the Company's transition plan in 2001. The Company's share of the future obligation to decommission these units is approximately $656 million in current dollars and (using a 4.0% escalation rate) approximately $1.6 billion 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 $163 million for decommissioning through its electric rates from customers through December 31, 2001. The Company has also recognized an estimated liability of approximately $7.6 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 July 2001, the Financial Accounting Standards Board issued SFAS 143, "Accounting for Asset Retirement Obligations." The new statement provides accounting treatment for retirement obligations associated with tangible long-lived assets with adoption required as of January 1, 2003. SFAS 143 requires 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. Upon retirement, a gain or loss will be recorded if the costs to settle the retirement obligation differs from the carrying amount. Under the new standard, additional assets and liabilities relating principally to nuclear decommissioning obligations will be recorded, the pattern of expense recognition will change and income from the external decommissioning trust will be recorded as investment income. The Company is currently assessing the new standard and has not yet quantified the impact on its financial statements. COMMON OWNERSHIP OF GENERATING FACILITIES- The Company, together with TE 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, 2001 include the following:
Utility Accumulated Construction Ownership/ Plant Provision for Work in Leasehold Generating Units in Service Depreciation Progress Interest --------------------------------------------------------------------------------------------------- (In millions) W. H. Sammis Unit 7........... $ 183.4 $123.9 $ -- 31.20% Bruce Mansfield Units 1, 2 and 3 84.7 35.0 22.0 20.42% Beaver Valley Unit 2.......... 2.3 0.5 7.1 24.47% Davis-Besse................... 209.8 33.4 12.9 51.38% Perry......................... 631.6 126.9 2.0 44.85% ---------------------------------------------------------------------------------------------------- Total....................... $1,111.8 $319.7 $44.0 ====================================================================================================
The Bruce Mansfield Plant is being leased through a sale and leaseback transaction (see Note 2) and the above-related amounts represent construction expenditures subsequent to the transaction. 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. 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. 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, 2001. The assets of the FirstEnergy pension plan consist primarily of common stocks, United States government bonds and corporate bonds. The FirstEnergy and GPU postretirement benefit plans are currently separately maintained; the information shown below is aggregated as of December 31, 2001. 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 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. The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Other Pension Benefits Postretirement Benefits 2001 2000 2001 2000 ---------------------------------------------------------------------------------------------- (In millions) Change in benefit obligation: Benefit obligation as of January 1...... $1,506.1 $1,394.1 $ 752.0 $ 608.4 Service cost............................ 34.9 27.4 18.3 11.3 Interest cost........................... 133.3 104.8 64.4 45.7 Plan amendments......................... 3.6 41.3 -- -- Actuarial loss.......................... 123.1 17.3 73.3 121.7 Voluntary early retirement program...... -- 23.4 2.3 -- GPU acquisition......................... 1,878.3 -- 716.9 -- Benefits paid........................... (131.4) (102.2) (45.6) (35.1) -------------------------------------------------------------------------------------------- Benefit obligation as of December 31.... 3,547.9 1,506.1 1,581.6 752.0 -------------------------------------------------------------------------------------------- Change in fair value of plan assets: Fair value of plan assets as of January 1 1,706.0 1,807.5 23.0 4.9 Actual return on plan assets............ 8.1 0.7 12.7 (0.2) Company contribution.................... -- -- 43.3 18.3 GPU acquisition......................... 1,901.0 -- 462.0 -- Benefits paid........................... (131.4) (102.2) (6.0) -- -------------------------------------------------------------------------------------------- Fair value of plan assets as of December 31 3,483.7 1,706.0 535.0 23.0 -------------------------------------------------------------------------------------------- Funded status of plan................... (64.2) 199.9 (1,046.6) (729.0) Unrecognized actuarial loss (gain)...... 222.8 (90.9) 212.8 147.3 Unrecognized prior service cost......... 87.9 93.1 17.7 20.9 Unrecognized net transition obligation (asset) -- (2.1) 101.6 110.9 -------------------------------------------------------------------------------------------- Prepaid (accrued) benefit cost.......... $ 246.5 $ 200.0 $ (714.5) $(449.9) ============================================================================================ Company's share of prepaid (accrued) benefit cost.......................... $ (32.7) $ (34.6) $ (195.9) $(188.8) ============================================================================================ Assumptions used as of December 31: Discount rate........................... 7.25% 7.75% 7.25% 7.75% Expected long-term return on plan assets 10.25% 10.25% 10.25% 10.25% Rate of compensation increase........... 4.00% 4.00% 4.00% 4.00%
FirstEnergy's net pension and other postretirement benefit costs for the three years ended December 31, 2001 were computed as follows:
Other Pension Benefits Postretirement Benefits ---------------- ------------------------ 2001 2000 1999 2001 2000 1999 ------------------------------------------------------------------------------------------------------- (In millions) Service cost............................ $ 34.9 $ 27.4 $ 28.3 $18.3 $11.3 $ 9.3 Interest cost........................... 133.3 104.8 102.0 64.4 45.7 40.7 Expected return on plan assets.......... (204.8) (181.0) (168.1) (9.9) (0.5) (0.4) Amortization of transition obligation (asset) (2.1) (7.9) (7.9) 9.2 9.2 9.2 Amortization of prior service cost...... 8.8 5.7 5.7 3.2 3.2 3.3 Recognized net actuarial loss (gain).... -- (9.1) -- 4.9 -- -- Voluntary early retirement program...... 6.1 17.2 -- 2.3 -- -- ------------------------------------------------------------------------------------------------------- Net benefit cost........................ $ (23.8) $ (42.9) $ (40.0) $92.4 $68.9 $62.1 ======================================================================================================= Company's share of net benefit cost..... $ (1.9) $ (5.3) $ (14.4) $12.5 $21.3 $22.0 -------------------------------------------------------------------------------------------------------
The composite health care trend rate assumption is approximately 10% in 2002, 9% in 2003 and 8% in 2004, trending to 4%-6% 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 trend rate assumption by one percentage point would increase the total service and interest cost components by $14.6 million and the postretirement benefit obligation by $151.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $12.7 million and the postretirement benefit obligation by $131.3 million. TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily TE, OE, Penn, ATSI, FirstEnergy Solutions Corp. (FES) and FirstEnergy. The Ohio transition plan, as discussed in the "Regulatory Plan" 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, TE, 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 TE. 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: 2001 2000 1999 -------------------------------------------------------------------------- (In millions) Operating Revenues: PSA revenues with FES............... $334.1 $ -- $ -- Generating units rent with FES...... 59.1 -- -- Ground lease with ATSI.............. 7.1 4.4 -- Operating Expenses: Purchased power under PSA........... 597.4 -- -- Purchased power from TE............. 97.0 106.8 106.1 ATSI rent expense................... 28.9 15.0 -- FirstEnergy support services........ 49.6 97.9 109.1 Other Income: Interest income from ATSI........... 7.2 2.4 -- Interest income from FES............ 0.9 -- -- -------------------------------------------------------------------------- The Company is buying 150 megawatts of TE's Beaver Valley Unit 2 leased capacity entitlement. Purchased power expense for this transaction was $97.0 million, $104.0 million and $104.3 million in 2001, 2000 and 1999, respectively. This purchase is expected to continue through the end of the lease period (See Note 2). 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. Noncash financing and investing activities included capital lease transactions amounting to $2.1 million, $52.0 million and $26.2 million in 2001, 2000 and 1999, respectively. 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, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31:
2001 2000 ---------------------------------------------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value ---------------------------------------------------------------------------------------------------------- (In millions) Long-term debt................................... $2,507 $2,624 $2,563 $2,655 Preferred stock.................................. $ 125 $ 125 $ 105 $ 105 Investments other than cash and cash equivalents: Debt securities - Maturity (5-10 years)....................... $ 11 $ 11 $ -- $ -- - Maturity (more than 10 years)............... 568 565 585 568 All other..................................... 214 218 202 210 ---------------------------------------------------------------------------------------------------------- $ 793 $ 794 $ 787 $ 778 ==========================================================================================================
The fair values of long-term debt and preferred stock subject to mandatory redemption 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 trust investments. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with corresponding changes to the decommissioning liability. 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 are expected to 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. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2001 2000 ------------------------------------------------------------------------ (In millions) Regulatory transition charge.................... $830.3 $767.9 Customer receivables for future income taxes.... 9.2 10.3 Loss on reacquired debt......................... 16.5 17.8 Other........................................... 18.5 20.1 ------------------------------------------------------------------------ Total...................................... $874.5 $816.1 ======================================================================== 2. LEASES: The Company leases certain generating 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 future minimum lease payments as of December 31, 2001 were approximately $1.1 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, 2001 are summarized as follows: 2001 2000 1999 --------------------------------------------------------------------- (In millions) Operating leases Interest element.... $35.3 $ 36.8 $ 38.6 Other............... 36.4 29.8 30.7 Capital leases Interest element.... 3.6 5.9 6.9 Other............... 19.4 37.4 41.3 --------------------------------------------------------------------- Total rentals....... $94.7 $109.9 $117.5 ===================================================================== The future minimum lease payments as of December 31, 2001 are: Operating Leases ----------------------------- Capital Lease Capital Leases Payments Trust Net ------------------------------------------------------------------------ (In millions) 2002........................... $ 1.0 $ 76.4 $ 70.6 $ 5.8 2003........................... 1.0 77.5 77.9 (0.4) 2004........................... 1.0 55.7 28.1 27.6 2005........................... 1.0 66.7 47.5 19.2 2006........................... 1.0 71.3 55.2 16.1 Years thereafter............... 5.7 582.5 433.5 149.0 ----------------------------------------------------------------------- Total minimum lease payments... 10.7 $930.1 $712.8 $217.3 ====== ====== ====== Interest portion............... 4.0 -------------------------------------- Present value of net minimum lease payments............... 6.7 Less current portion........... .3 -------------------------------------- Noncurrent portion............. $ 6.4 ====================================== 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 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 ($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. The Shippingport Capital Trust arrangement effectively reduces lease costs related to that transaction. 3. CAPITALIZATION: (A) RETAINED EARNINGS- There are no restrictions on retained earnings for payment of cash dividends on the Company's common stock. The 1997 FirstEnergy merger purchase accounting adjustments included resetting the retained earnings balance to zero at the November 8, 1997 merger date. (B) STOCK COMPENSATION PLANS- Employees of the Company participate in stock based plans administered by FirstEnergy which include the Centerior Equity Plan (CEI Plan) and 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 15 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. Under the Executive Deferred Compensation Plan, 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 occurs three years from the date of deferral. The Company continues to apply APB 25, "Accounting for Stock Issued to Employees." As required by SFAS 123, "Accounting for Stock-Based Compensation," the Company has determined pro forma earnings as though the Company had accounted for employee stock options under the fair value method. The weighted average assumptions used in valuing the options and their resulting fair values are as follows: 2001 2000 1999 ---------------------------------------------------------------------------- Valuation assumptions: Expected option term (years) 8.3 7.6 6.4 Expected volatility......... 23.45% 21.77% 20.03% Expected dividend yield..... 5.00% 6.68% 5.97% Risk-free interest rate..... 4.67% 5.28% 5.97% Fair value per option......... $4.97 $2.86 $3.42 -------------------------------------------------------------------------- The following table summarizes the pro forma effect of applying fair value accounting to the Company's stock options. 2001 2000 1999 ---------------------------------------------------------------------------- Earnings on Company Stock (000) As Reported................. $193,206 $182,107 $160,565 Pro Forma................... $192,784 $181,742 $160,403 ---------------------------------------------------------------------------- (C) PREFERRED AND PREFERENCE STOCK- The Company's $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 2001. The Company redeemed, pursuant to redemption provisions of its $42.40 Series T issue, all 200,000 shares outstanding on February 1, 2002 at a price of $500 per share. The Company has three million authorized and unissued shares of preference stock having no par value. (D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- Annual sinking fund provisions currently in effect for preferred stock are as follows: Redemption Price Per Series Shares Share -------------------------------------------------------- $ 7.35 C 10,000 $ 100 90.00 S 17,750 1,000 -------------------------------------------------------- Annual sinking fund requirements for the next five years are $18.0 million in 2002 and $1.0 million in each year 2003-2006. (E) COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES- CFT, a wholly owned subsidiary of the Company, issued $100 million of 9% Cumulative Trust Preferred Capital Securities in December 2001. The Company purchased all of the Trust's Common Securities and simultaneously issued to the Trust $103.1 million principal amount of 9% Junior Subordinated Debentures due 2031 in exchange for the proceeds that the Trust received from its sale of Preferred and Common Securities. The sole assets of the Trust are the Subordinated Debentures whose interest and other payment dates coincide with the distribution and other payment dates on the Trust Securities. Under certain circumstances, the Subordinated Debentures could be distributed to the holders of the outstanding Trust Securities in the event the Trust is liquidated. Beginning in December 2006, the Subordinated Debentures may be optionally redeemed by the Company at a redemption price of $25 per Subordinated Debenture plus accrued interest, in which event the Trust Securities will be redeemed on a pro rata basis at $25 per share plus accumulated distributions. The Company's obligations under the Subordinated Debentures along with the related Indenture, Trust Agreement, Guarantee Agreement and the Agreement for expenses and liabilities, constitute a full and unconditional guarantee by the Company of payments due on the Preferred Securities. (F) 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) --------------------------------------------- 2002................................. $411.4 2003................................. 196.7 2004................................. 307.7 2005................................. 300.0 2006................................. -- --------------------------------------------- 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 an irrevocable bank letter of credit of $48.1 million and noncancelable municipal bond insurance policies of $112.6 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letter of credit, the Company is entitled to a credit against its obligation to repay that bond. The Company pays an annual fee of 1.00% 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 $222 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in May 2002. 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 2). 4. SHORT-TERM BORROWINGS: The Company may borrow from its affiliates on a short-term basis. As of December 31, 2001, the Company had total short-term borrowings of $97.7 million from its affiliates with a weighted average interest rate of approximately 3.5%. 5. COMMITMENTS AND CONTINGENCIES: CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $392 million for property additions and improvements from 2002-2006, of which approximately $121 million is applicable to 2002. Investments for additional nuclear fuel during the 2002-2006 period are estimated to be approximately $176 million, of which approximately $19 million applies to 2002. During the same periods, the Company's nuclear fuel investments are expected to be reduced by approximately $163 million and $32 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 $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 $106.3 million per incident but not more than $12.1 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 $382 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 $22 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. 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. 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 $27,500 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 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 "draft" SIP that requires compliance with the NOx budgets at the Company's Ohio facilities by May 31, 2004. FirstEnergy continues to evaluate its compliance plans and other compliance options. 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. In April 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. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. The Company has accrued a liability of $2.9 million as of December 31, 2001, based on estimates of the total costs of cleanup, the proportionate responsibility of other PRPs for such costs and the financial ability of other PRPs to pay. The Company believes that waste disposal costs will not have a material adverse effect on its financial condition, cash flows or results of operations. Legal Matters 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: On November 29, 2001, FirstEnergy reached an agreement to sell four coal-fired power plants (with an aggregate net book value of $539 million as of December 31, 2001) totaling 2,535 MW to NRG Energy Inc. (NRG) for $1.5 billion ($1.355 billion in cash and $145 million in debt assumption). The sale includes the 376 MW Ashtabula, 1,262 MW Eastlake and 249 MW Lakeshore plants owned by the Company (with an aggregate net book value of $393 million as of December 31, 2001). The net, after-tax gain from the sale, based on the difference between the sale price of the plants and their market price used in the Ohio restructuring transition plan, will be credited to customers by reducing the transition cost recovery period. FirstEnergy also entered into a power purchase agreement (PPA) with NRG. Under the terms of the PPA, NRG is obligated to sell up to 10.5 billion kilowatt-hours of electricity annually, similar to the average annual output of the plants, through 2005. The sale is expected to close in mid-2002. 7. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2001 and 2000.
March 31, June 30, September 30, December 31, Three Months Ended 2001 2001 2001 2001 ----------------------------------------------------------------------------------------------------- (In millions) Operating Revenues.................. $516.4 $498.8 $603.3 $457.7 Operating Expenses and Taxes........ 463.0 420.2 430.0 367.4 ----------------------------------------------------------------------------------------------------- Operating Income.................... 53.4 78.6 173.3 90.3 Other Income........................ 4.4 1.1 4.0 3.7 Net Interest Charges................ 46.2 47.2 48.4 48.0 ----------------------------------------------------------------------------------------------------- Net Income.......................... $ 11.6 $ 32.5 $128.9 $ 46.0 ===================================================================================================== Earnings on Common Stock............ $ 5.1 $ 25.4 $122.6 $ 40.1 =====================================================================================================
March 31, June 30, September 30, December 31, Three Months Ended 2000 2000 2000 2000 ------------------------------------------------------------------------------------------------------ (In millions) Operating Revenues................... $423.7 $470.6 $525.4 $467.3 Operating Expenses and Taxes......... 336.9 383.7 396.0 380.3 ------------------------------------------------------------------------------------------------------ Operating Income..................... 86.8 86.9 129.4 87.0 Other Income......................... 3.4 2.9 3.8 2.5 Net Interest Charges................. 51.5 50.5 49.2 48.5 ----------------------------------------------------------------------------------------------------- Net Income........................... $ 38.7 $ 39.3 $ 84.0 $ 41.0 ====================================================================================================== Earnings on Common Stock............. $ 30.9 $ 32.6 $ 80.3 $ 38.3 ======================================================================================================
Report of Independent Public Accountants To the Stockholders and Board of Directors of The Cleveland Electric Illuminating Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Cleveland Electric Illuminating Company (an Ohio corporation and wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 2001. 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 audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002.