EX-13.2 20 ex13-2.txt ANNUAL REPORT - CEI THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 2000 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 2-6 Consolidated Statements of Income 7 Consolidated Balance Sheets 8 Consolidated Statements of Capitalization 9-10 Consolidated Statements of Common Stockholder's Equity 11 Consolidated Statements of Preferred Stock 11 Consolidated Statements of Cash Flows 12 Consolidated Statements of Taxes 13 Notes to Consolidated Financial Statements 14-23 Report of Independent Public Accountants 24 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY SELECTED FINANCIAL DATA

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. Results of Operations --------------------- Earnings on common stock increased 13% to $182.1 million in 2000 from $160.6 million in 1999. Results in 2000 were favorably affected by higher operating revenues and reduced depreciation and amortization, net interest charges and preferred stock dividend requirements. In 1999, earnings on common stock increased 15% to $160.6 million from $140 million in 1998 primarily due to higher operating revenues, the absence of unusually high purchased power costs experienced in 1998, reduced general taxes and lower net interest charges. Partially offsetting the improved earnings in both 2000 and 1999 were higher nuclear and other operating costs. Operating revenues increased by $22.1 million in 2000 following a $69.0 million increase in 1999. The sources of increases in operating revenues during 2000 and 1999, as compared to the prior year, are summarized in the following table. Sources of Revenue Changes 2000 1999 ----------------------------------------------------------- Increase (Decrease) (In millions) Increase in retail kilowatt-hour sales $ 15.6 $46.1 Change in average retail price (37.9) (1.5) Increase in wholesale sales 56.1 15.2 All other changes (11.7) 9.2 ----------------------------------------------------------- Net Increase in Operating Revenues $ 22.1 $69.0 ========================================================== Electric 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 (Duquesne) in 2000 resulting from the 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. Operating revenues in 1999 increased from the preceding year as a result of kilowatt-hour sales growth in both the retail and wholesale markets. Strong consumer-driven economic growth, and to a lesser extent the weather, contributed to the increased retail sales. Weather-induced electricity demand in the wholesale market and additional available internal generation combined to more than double sales to wholesale customers in 1999, compared to 1998. Changes in kilowatt-hour sales by customer class in 2000 and 1999 are summarized in the following table: Changes in KWH Sales 2000 1999 ------------------------------------------------ Increase (Decrease) Residential (4.1)% 6.6% Commercial 2.3% 2.5% Industrial 3.1% 0.6% ------------------------------------------------ Total Retail 0.9% 2.7% Wholesale 77.6% 104.5% ------------------------------------------------ Total Sales 9.8% 9.0% ------------------------------------------------ Operating Expenses and Taxes Total operating expenses and taxes increased $26.8 million in 2000 and $56.7 million in 1999, compared to the respective preceding year. Collectively, nuclear and other operating costs represented a majority of the increased costs in 2000 and all of the increase in 1999. General taxes were also higher in 2000. Fuel and purchased power costs increased a moderate $4.8 million in 2000, 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. Factors contributing to the lower fuel expense included: o A higher proportion of nuclear generation (which has lower unit fuel costs than fossil fuel) due to increased nuclear ownership from the exchange of generating assets with Duquesne in December 1999; o The expiration of an above-market coal contract at the end of 1999; and o Continued improvement of coal-blending strategies, which resulted in the use of additional lower-cost coal and enhanced the efficiency and cost-competitiveness of our fossil generation. In 1999, lower purchased power costs accounted for almost all of the $26.5 million reduction in fuel and purchased power costs from the prior year. Much of the decrease in purchased power costs occurred in the second quarter of 1999 due to the absence of unusual conditions experienced in the summer of 1998. The higher purchased power costs were incurred during a period of record heat and humidity in late June 1998, which coincided with a regional power shortage resulting in high prices for purchased power. Unscheduled outages at Beaver Valley Unit 2, the Davis-Besse Plant and Avon Lake Unit 9 required us to purchase significant amounts of power on the spot market during that period. Although above normal temperatures were also experienced in 1999, we maintained a stronger capacity position compared to the previous year and better met customer demand from our own internal generation. Nuclear operating costs increased $12.9 million in 2000, compared to 1999, primarily due to additional refueling outage costs associated with three unit outages in 2000 versus two during the previous year and increased ownership of the Perry Plant resulting from the Duquesne asset swap. Nuclear refueling outage costs at Beaver Valley Unit 2 and the Perry Plant were primarily responsible for the $40.8 million increase in 1999 nuclear operating costs from the preceding year. Other operating costs rose $6.7 million in 2000, compared to 1999, with most of the increase resulting from additional leased portable diesel generators, acquired as part of our summer supply strategy, 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. Other operating costs increased $32.5 million in 1999 from 1998 due to higher customer and sales expenses including expenditures for energy marketing programs, information system requirements and other customer- related costs. Approval of our transition plan by the Public Utilities Commission of Ohio (PUCO) resulted in a net reduction of depreciation and amortization in 2000, compared to 1999. 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. 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 decreased by $10.1 million in 2000 and $19.6 million in 1999, compared to the prior year. We continue to redeem our outstanding debt, thus maintaining the downward trend in our financing costs during 2000. Net redemptions of long-term debt totaled $175 million in 2000. 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 maturities and the amortization of fair market value adjustments recognized under purchase accounting in 1997. In 1999, preferred stock dividend requirements were $8.7 million higher due to a reduction in 1998 resulting from the declaration of $9 million of preferred dividends as of the 1997 merger date, for dividends attributable to 1998. Effects of SFAS 71 Discontinuation and Impairment ------------------------------------------------- The application of the Statement of Financial Accounting Standards No. (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," was discontinued for our nonnuclear generation business effective with approval by the PUCO of the Ohio transition plan. We continue to bill and collect cost-based rates for transmission and distribution services, which remain subject to cost-based regulation; accordingly, it is appropriate that we continue the application of SFAS 71 to those operations. All generating plant investments were reviewed for impairment due to anticipated changes to our cash flows resulting from the transition plan. The June 30, 2000 balance sheet reflects the effect of that review with nuclear plant investment being further reduced by a total of $304 million with a corresponding recognition of regulatory assets for the impaired plant, which is recoverable through future regulatory cash flows. Financial Condition, Capital Resources and Liquidity ---------------------------------------------------- On September 1, 2000, FirstEnergy Corp.'s electric utility operating companies transferred $1.2 billion of their transmission assets to American Transmission Systems, Inc. (ATSI), an affiliated company. ATSI represents a first step toward the goal of establishing a larger independent, regional transmission organization. As part of the transfer, we sold to ATSI $328.1 million of our transmission assets, net of $155.2 million of accumulated depreciation and $3.4 million of investment tax credits for $76.3 million in cash and $93.2 million in long-term notes. Through net debt redemptions and preferred stock sinking fund maturities, we continued to reduce the cost of debt and preferred stock, and improve our financial position in 2000. During 2000, we reduced our total debt by approximately $245 million. Our common stockholder's equity percentage of capitalization increased to 27% as of December 31, 2000 from 21% at the end of 1997. We have reduced the average capital cost of outstanding debt from 8.88% in 1995 to 8.07% in 2000. Net redemptions of long-term debt and preferred stock completed in 2000 are expected to generate annual savings of about $15 million. Also, approval by the PUCO of our transition plan on July 19, 2000 (see Outlook), was cited as an important reason that Moody's Investors Service and Fitch upgraded our debt ratings during the second half of 2000. The improved credit ratings should lower the cost of future borrowings. Our credit ratings remain under review for further possible upgrades by Moody's. The improved credit ratings are summarized in the following table: Credit Ratings Before Upgrade After Upgrade ------------------------------------------------------------- Moody's Moody's Investors Investors Service Fitch Service Fitch ------------------------------------------------------------- First mortgage bonds Ba1 BB+ Baa3 BBB- Preferred Stock b1 B baa1 BB Our cash requirements in 2001 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without issuing additional securities. We have cash requirements of approximately $1.1 billion for the 2001-2005 period to meet scheduled maturities of long-term debt and preferred stock. Of that amount, approximately $137.0 million relates to 2001. We had about $3.2 million of cash and temporary investments and $28.6 million of short-term indebtedness to associated companies on December 31, 2000. Under our first mortgage indenture, as of December 31, 2000, we would have been permitted to issue up to $829 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 capital spending for the period 2001-2005 is expected to be about $455 million (excluding nuclear fuel), of which approximately $103 million applies to 2001. Investments for additional nuclear fuel during the 2001-2005 period are estimated to be approximately $114 million, of which about $8 million relates to 2001. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $144 million and $32 million, respectively, as the nuclear fuel is consumed. Also, we have operating lease commitments net of trust cash receipts of approximately $74 million for the 2001-2005 period, of which approximately $22 million relates to 2001. 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 interest rate 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. 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.

Outlook ------- On July 19, 2000, the PUCO approved FirstEnergy's plan for transition to customer choice in Ohio (see Note 1), filed on our behalf, as well as for our affiliated Ohio electric utility operating companies - OE and TE. As part of its authorization, the PUCO approved a settlement agreement between FirstEnergy and major groups representing most of FirstEnergy's Ohio customers regarding the transition to customer choice in selection of electricity suppliers. On January 1, 2001, electric choice became available to FirstEnergy's Ohio customers. Under the plan, we continue to deliver power to homes and businesses through our existing distribution system, which remains regulated. However, our rates have been restructured to establish separate charges for transmission and distribution, transition cost recovery and a generation-related component. When one of our Ohio customers elects to obtain power from an alternative supplier, we reduce the customer's bill with a "generation shopping credit," based on market prices plus an incentive, and the customer receives a generation charge from the alternative supplier. The transition cost portion of rates provides for recovery of certain amounts not otherwise recoverable in a competitive generation market (such as regulatory assets). The transition costs will be paid by all customers regardless of whether or not they choose an alternative supplier. Under the plan, we assume the risk of not recovering up to $170 million of transition revenue if the rate of customers (excluding contracts and full-service accounts), switching their service from us has not reached an average of 20% over any consecutive twelve-month period by December 31, 2005 - the end of the market development period. We 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 Ohio service areas. Through February 8, 2001, approximately 305 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 February 8, 2001, we had been notified that about 51,000 of our customers requested generation services from other authorized suppliers, including FirstEnergy Services Corp. (FE Services), an affiliated company. Beginning in 2001, Ohio utilities that offer both competitive and regulated retail electric services must implement a corporate separation plan approved by the PUCO -- one which provides a clear separation between regulated and competitive operations. Since FirstEnergy's regionally-focused retail sales strategy envisions the continued operation of both regulated and competitive operations, its transition plan included details for its corporate separation. The approved plan is consistent with the way FirstEnergy managed its businesses in 2000, through a competitive services unit, a utility services unit and a corporate support services unit. FE Services provides competitive retail energy services while we continue to provide regulated transmission and distribution services. FirstEnergy Generation Corp. (FE Generation), an associated company, operates and leases fossil plants from us. We expect that the transfer of our fossil generating assets to FE Generation will be completed by the end of the market development period. All of our power supply requirements are provided by FE Services to satisfy our "provider of last resort" obligation under the FirstEnergy transition plan, as well as grandfathered wholesale contracts. We are in compliance with current sulfur dioxide and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the EPA finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities (see Note 5). We continue to evaluate our compliance plans and other compliance options. In July 1997, the EPA changed 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 on the manner in which they are ultimately implemented, if at all, by the states in which we operate affected facilities. Under federal environmental law and related federal and state waste regulations, certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. On April 25, 2000, the EPA announced that it will develop national standards regulating disposal of coal ash as a nonhazardous waste. 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. 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 an accrued liability totaling $3.4 million as of December 31, 2000, 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 flow or results of operation. On August 8, 2000, our parent company, FirstEnergy Corp., entered into an agreement to merge with GPU, Inc, a Pennsylvania corporation, headquartered in Morristown, New Jersey. The target date for completing the merger is by the end of the second quarter of 2001. We will continue to be a wholly owned subsidiary of FirstEnergy Corp. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

CONSOLIDATED STATEMENTS OF PREFERRED STOCK

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF TAXES

Other Pension Benefits Postretirement Benefits ---------------- ------------------------ 2000 1999 2000 1999 ------------------------------------------------------------------------- (In millions) Change in benefit obligation: Benefit obligation as of January 1 $1,394.1 $1,500.1 $ 608.4 $ 601.3 Service cost 27.4 28.3 11.3 9.3 Interest cost 104.8 102.0 45.7 40.7 Plan amendments 41.3 -- -- -- Actuarial loss (gain) 17.3 (155.6) 121.7 (17.6) Net increase from asset swap -- 14.8 -- 12.5 Voluntary early retirement program expense 23.4 -- -- -- Benefits paid (102.2) (95.5) (35.1) (37.8) ------------------------------------------------------------------------- Benefit obligation as of December 31 1,506.1 1,394.1 752.0 608.4 ------------------------------------------------------------------------- Change in plan assets: Fair value of plan assets as of January 1 1,807.5 1,683.0 4.9 3.9 Actual return on plan assets 0.7 220.0 (0.2) 0.6 Company contribution -- -- 18.3 0.4 Benefits paid (102.2) (95.5) -- -- ------------------------------------------------------------------------- Fair value of plan assets as of December 31 1,706.0 1,807.5 23.0 4.9 ------------------------------------------------------------------------- Funded status of plan 199.9 413.4 (729.0) (603.5) Unrecognized actuarial loss (gain) (90.9) (303.5) 147.3 24.9 Unrecognized prior service cost 93.1 57.3 20.9 24.1 Unrecognized net transition obligation (asset) (2.1) (10.1) 110.9 120.1 ------------------------------------------------------------------------- Prepaid (accrued) benefit cost $ 200.0 $ 157.1 $(449.9) $(434.4) ========================================================================= Company's share of accrued benefit cost $ (34.6) $ (39.9) $(188.8) $(179.0) ========================================================================= Assumptions used as of December 31: Discount rate 7.75% 7.75% 7.75% 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, 2000 were computed as follows:
Other Pension Benefits Postretirement Benefits -------------------- ----------------------- 2000 1999 1998 2000 1999 1998 ------------------------------------------------------------------------- (In millions) Service cost $ 27.4 $ 28.3 $ 25.0 $11.3 $ 9.3 $ 7.5 Interest cost 104.8 102.0 92.5 45.7 40.7 37.6 Expected return on plan assets (181.0) (168.1) (152.7) (0.5) (0.4) (0.3) Amortization of transition obligation (asset) (7.9) (7.9) (8.0) 9.2 9.2 9.2 Amortization of prior service cost 5.7 5.7 2.3 3.2 3.3 (0.8) Recognized net actuarial loss (gain) (9.1) -- (2.6) -- -- -- Voluntary early retirement program expense 17.2 -- -- -- -- -- ------------------------------------------------------------------------- Net benefit cost $ (42.9) $ (40.0) $ (43.5) $68.9 $62.1 $53.2 ========================================================================= Company's share of total plan costs $ (5.3) $ (14.4) $ (2.7) $21.3 $22.0 $14.5 -------------------------------------------------------------------------
The FirstEnergy plan's health care trend rate assumption is 7.2% in 2001, 7.0% in 2002 and 6.5% in 2003, trending to 5.0%-5.5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care trend rate assumption by one percentage point would increase the total service and interest cost components by $7.5 million and the postretirement benefit obligation by $94.4 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $8.5 million and the postretirement benefit obligation by $111.0 million. TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and interest charges include transactions with TE, OE, Penn and ATSI. Primary transactions include purchased power and transmission facilities rent expenses of $15.0 million from ATSI starting in 2000. CFC serves as the transferor in connection with the accounts receivable securitization for the Company and TE. The Company is buying 150 megawatts of TE's Beaver Valley Unit 2 leased capacity entitlement. Purchased power expense for this transaction was $104.0 million, $104.3 million and $98.5 million in 2000, 1999 and 1998, respectively. This purchase is expected to continue through the end of the lease period. (See Note 2.) Fuel and purchased power expenses on the Consolidated Statements of Income include the total costs of power purchased from TE of $106.8 million, $106.1 million and $104.7 million in 2000, 1999 and 1998, respectively. FirstEnergy and, prior to 1999, the Centerior Service Company (CSC), a wholly owned subsidiary of FirstEnergy, provides support services at cost to the Company and other affiliated companies, for which the Company was billed $97.9 million in 2000 and $109.1 million in 1999 by FirstEnergy, and $80.6 million in 1998 by CSC. SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets. The Company reflects temporary cash investments at cost, which approximates their fair market value. Noncash financing and investing activities included capital lease transactions amounting to $52.0 million, $26.2 million and $32.3 million in 2000, 1999 and 1998, 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: 2000 1999 -------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value -------------------------------------------------------------------- (In millions) Long-term debt $2,563 $2,655 $2,738 $2,711 Preferred stock $ 107 $ 105 $ 150 $ 139 Investments other than cash and cash equivalents: Debt securities - (Maturing in more than 10 years) $ 585 $ 568 $ 517 $ 476 All other 202 210 193 200 --------------------------------------------------------------------- $ 787 $ 778 $ 710 $ 676 ==================================================================== 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 will continue to be recovered from customers under the Company's transition plan. Based on that plan, the Company continues to bill and collect cost-based rates for its transmission and distribution services, which will remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations. The application of SFAS 71 to the Company's nonnuclear generation business was discontinued effective with the PUCO's approval of FirstEnergy's transition plan. All generating plant investments were reviewed for impairment due to the anticipated regulatory cash flows under the transition plan. The effect of that review was reflected on the financial statements as of June 30, 2000, with the reduction of plant investment and the corresponding recognition of regulatory assets recoverable through future regulatory cash flows for generating assets that were impaired of approximately $304 million for the Company. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2000 1999 ------------------------------------------------------------------ (In millions) Nuclear unit expenses $ 276.1 $ 287.1 Customer receivables for future income taxes 18.1 23.0 Rate stabilization program deferrals 251.7 263.9 Sale and leaseback costs (131.9) (136.4) Loss on reacquired debt 70.5 75.9 Impaired generating assets 304.3 -- Other 27.3 26.3 ------------------------------------------------------------------- Total $ 816.1 $ 539.8 ================================================================== 2. LEASES: The Company leases certain generating facilities, nuclear fuel, 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, 2000 were approximately $1.2 billion, net of trust cash receipts.) Nuclear fuel is currently financed for the Company and TE through leases with a special-purpose corporation. As of December 31, 2000, $142 million of nuclear fuel ($86 million for the Company) was financed under a lease financing arrangement totaling $150 million from bank credit arrangements. The bank credit arrangements expire in August 2001. Lease rates are based on bank rates and commercial paper rates. Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2000 and are summarized as follows:
2000 1999 1998 ------------------------------------------------------------------- (In millions) Operating leases Interest element $ 36.8 $ 38.6 $ 32.4 Other 29.8 30.7 74.4 Capital leases Interest element 5.9 6.9 7.0 Other 37.4 41.3 36.1 ------------------------------------------------------------------- Total rentals $109.9 $117.5 $149.9 ===================================================================
The future minimum lease payments as of December 31, 2000 are:
Operating Leases --------------------------- Capital Lease Capital Leases Payments Trust Net ---------------------------------------------------------------------- (In millions) 2001 $ 41.0 $ 71.7 $ 50.2 $ 21.5 2002 28.1 76.4 70.6 5.8 2003 17.3 77.5 77.9 (0.4) 2004 10.2 55.7 28.2 27.5 2005 3.7 66.7 47.5 19.2 Years thereafter 8.4 653.8 488.7 165.1 ----------------------------------------------------------------------- Total minimum lease payments 108.7 $1,001.8 $763.1 $238.7 Interest portion 15.3 ======== ====== ====== ------------------------------------ Present value of net minimum lease payments 93.4 Less current portion 28.7 ------------------------------------ Noncurrent portion $ 64.7 ===================================
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) PREFERRED AND PREFERENCE STOCK- The Company's $88.00 Series R preferred stock is not redeemable before December 2001 and its $90.00 Series S has no optional redemption provision. All other preferred stock may be redeemed by the Company in whole, or in part, with 30-90 days' notice. The preferred dividend rate on the Company's Series L fluctuates based on prevailing interest rates and market conditions. The dividend rate for this issue was 7% in 2000. The Company has three million authorized and unissued shares of preference stock having no par value. (C) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- Annual sinking fund provisions for preferred stock are as follows: Redemption Price Per Series Shares Share Date Beginning -------------------------------------------------------------------- $ 7.35 C 10,000 $ 100 (i) 91.50 Q 10,714 1,000 (i) 90.00 S 18,750 1,000 (i) 88.00 R 50,000 1,000 December 1 2001 -------------------------------------------------------------------- (i) Sinking fund provisions are in effect. Annual sinking fund requirements for the next five years are $80.5 million in 2001, $18.0 million in 2002 and $1.0 million in each year 2003-2005. (D) LONG-TERM DEBT- The first mortgage indenture and its supplements, which secure all of the Company's first mortgage bonds, serve as direct first mortgage liens on substantially all property and franchises, other than specifically excepted property, owned by the Company. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) ---------------------- 2001 $ 56.5 2002 228.0 2003 115.0 2004 307.7 2005 300.0 ---------------------- 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 1.375% 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, 2000, the Company had total short-term borrowings of $28.6 million from its affiliates with a weighted average interest rate of approximately 6.4%. 5. COMMITMENTS AND CONTINGENCIES: CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $455 million for property additions and improvements from 2001-2005, of which approximately $103 million is applicable to 2001. Investments for additional nuclear fuel during the 2001-2005 period are estimated to be approximately $114 million, of which approximately $8 million applies to 2001. During the same periods, the Company's nuclear fuel investments are expected to be reduced by approximately $144 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 $255.2 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 $11.8 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. The Company estimates additional capital expenditures for environmental compliance of approximately $41 million, which is included in the construction forecast provided under "Capital Expenditures" for 2001 through 2005. 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 twenty-two 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. In March 2000, the U.S. Court of Appeals for the D.C. Circuit upheld EPA's NOx Transport Rule except as applied to the State of Wisconsin and portions of Georgia and Missouri. By October 2000, states were to submit revised State Implementation Plans (SIP) to comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania recently 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. A Federal Implementation Plan accompanied the NOx Transport Rule and may be implemented by the EPA in states which fail to revise their SIP. In another separate but related action, eight states filed petitions with the EPA under Section 126 of the Clean Air Act seeking reductions of NOx emissions which are alleged to contribute to ozone pollution in the eight petitioning states. The EPA position is that the Section 126 petitions will be adequately addressed by the NOx Transport Program, but a December 17, 1999 rulemaking established an alternative program which would require nearly identical 85% NOx reductions at 392 utility plants, including the Company's Ohio and Pennsylvania plants, by May 2003, in the event implementation of the NOx Transport Rule is not implemented by a state. Additional Section 126 petitions were filed by New Jersey, Maryland, Delaware and the District of Columbia in mid-1999 and are still under evaluation by the EPA. 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 on the manner in which they are ultimately implemented, if at all, by the states in which the Company operates affected facilities. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. On April 25, 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. The Company has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved, are often unsubstantiated and subject to dispute. 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 $3.4 million as of December 31, 2000, 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. 6. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2000 and 1999.
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 ========================================================================

March 31, June 30, September 30, December 31, Three Months Ended 1999 1999 1999 1999 ------------------------------------------------------------------------- (In millions) Operating Revenues $418.8 $481.9 $534.5 $429.7 Operating Expenses and Taxes 337.3 375.3 395.6 362.0 ------------------------------------------------------------------------- Operating Income 81.5 106.6 138.9 67.7 Other Income (Expense) 6.5 (1.2) 1.3 2.7 Net Interest Charges 53.1 52.8 52.2 51.8 ------------------------------------------------------------------------ Net Income $ 34.9 $ 52.6 $ 88.0 $ 18.6 ======================================================================== Earnings on Common Stock $ 26.4 $ 44.1 $ 79.7 $ 10.4 ========================================================================
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 subsidiary as of December 31, 2000 and 1999, 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, 2000. 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 subsidiary as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, February 16, 2001. 22