EX-13.1 16 ex13-1.txt ANNUAL REPORT - OE OHIO EDISON COMPANY 2000 ANNUAL REPORT TO STOCKHOLDERS Ohio Edison Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. Ohio Edison engages in the generation, distribution and sale of electric energy to communities in an area of 7,500 square miles in central and northeastern Ohio. It also engages in the sale, purchase and interchange of electric energy with other electric companies. Contents Page -------- ---- Selected Financial Data 1 Management's Discussion and Analysis 2-7 Consolidated Statements of Income 8 Consolidated Balance Sheets 9 Consolidated Statements of Capitalization 10-11 Consolidated Statements of Common Stockholder's Equity 12 Consolidated Statements of Preferred Stock 12 Consolidated Statements of Cash Flows 13 Consolidated Statements of Taxes 14 Notes to Consolidated Financial Statements 15-25 Report of Independent Public Accountants 26 OHIO EDISON COMPANY SELECTED FINANCIAL DATA

OHIO EDISON 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 for 2000 increased 14% to $325.3 million from $286.1 million in 1999. Results for 2000 were favorably affected by higher operating revenues, lower fuel expenses, and reductions in general taxes and net interest charges, which were partially offset by higher nuclear and other operating costs. In 1999, earnings on common stock increased 11% to $286.1 million from $258.8 million in 1998 primarily due to higher operating revenues, the absence of an extraordinary charge and unusually high purchased power costs experienced in 1998 and lower interest costs that were principally offset by an increase in depreciation and amortization. Operating revenues increased by $39.8 million in 2000 following a $167.3 million increase in 1999. The sources of increases in operating revenues during 2000 and 1999 are summarized in the following table: Sources of Revenue Changes 2000 1999 -------------------------------------------------------- Increase (Decrease) (In millions) Change in retail kilowatt-hour sales $(12.6) $151.3 Decrease in average retail price (2.9) (36.3) Increase in wholesale sales 33.2 54.6 Increase in transmission-related services 18.9 0.4 All other changes 3.2 (2.7) --------------------------------------------------------- Net Increase in Operating Revenues $ 39.8 $167.3 ========================================================= 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, primarily due to additional available generating capacity. Transmission-related revenues also contributed to the increase in operating revenues in 2000. These increases were partially offset by lower retail kilowatt-hour sales and a reduction in the average retail unit price resulting from the transition rate credit program and a changing sales mix. Retail kilowatt-hour sales to industrial customers increased while kilowatt-hour sales to both residential and commercial customers decreased in 2000 from the previous year. The overall reduction in retail kilowatt-hour sales reflected a softening in the service area economy and cooler summer weather during 2000, compared to the above-normal temperatures experienced in 1999. Sales growth in both the retail and wholesale markets produced the increase in operating revenues in 1999, compared to 1998. 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 generation combined to increase sales to wholesale customers. 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 (1.3)% 8.1% Commercial (2.5)% 8.6% Industrial 1.6% 4.7% -------------------------------------------------- Total Retail (0.5)% 6.8% Wholesale 43.3% 20.6% -------------------------------------------------- Total Sales 7.8% 9.2% -------------------------------------------------- Operating Expenses and Taxes Total operating expenses and taxes increased $30.5 million in 2000 and $181.2 million in 1999. The increase in 2000 resulted primarily from higher operation and maintenance costs. While operation and maintenance costs were also up in 1999, the increase in operating expenses and taxes in that year was principally due to additional depreciation and amortization. The increases in operation and maintenance costs in both 2000 and 1999 occurred despite a reduction in fuel and purchased power costs. Fuel expenses were $56.0 million lower in 2000, compared to 1999, which accounted for nearly all of the reduction in fuel and purchased power costs. Several factors contributed to the lower fuel expense, which occurred despite an 11.1% increase in output from our generating units. Factors contributing to lower fuel expense included: o A higher proportion of nuclear generation (which has lower unit fuel costs than fossil fuel) due to improved nuclear availability and increased nuclear ownership from the exchange of generating assets with Duquesne Light Company (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 fuel and enhanced the efficiency and cost-competitiveness of our fossil generation. In 1999, the entire $35.8 million reduction in fuel and purchased power costs was due to lower purchased power costs. Much of the decrease occurred in the second quarter of 1999 due to the absence of unusual conditions experienced in the summer of 1998. Those 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 Units 1 and 2 at the same time required us to purchase significant amounts of power on the spot market. 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 generation sources. Nuclear operating costs increased by $54.1 million in 2000 and $32.4 million in 1999 due to refueling outage costs and increased ownership of the Beaver Valley Plant following the Duquesne asset swap in early December 1999. Increased Beaver Valley Plant ownership (including nonrecurring swap-related liabilities assumed) also contributed to higher nuclear operating costs in 1999 compared to the preceding year, along with outage-related costs at Beaver Valley Unit 2 and the Perry Plant. Other operating costs rose $23.8 million in 2000, compared to 1999, with most of the increase resulting from higher transmission costs in the fourth quarter as American Transmission Systems, Inc. (ATSI), an affiliated company, assumed responsibility for transmission operations and charged us for transmission services (see Financial Condition, Capital Resources and Liquidity). The impact of the higher transmission costs was offset in part by income received from ATSI under a ground lease arrangement and interest income from the promissory note received in connection with the sale of the transmission facilities. Also contributing to the increase in other operating costs in 2000 were higher reserves established for potentially uncollectible accounts of customers in the steel sector who are experiencing significant financial pressures from foreign steel competition, and the cost of additional leased portable diesel generators, acquired as part of our summer supply strategy. Partially offsetting those higher operating costs were $11.9 million in increased gains realized from the sale of emission allowances. In 1999, higher customer and sales expenses, including expenditures for energy marketing programs, information system requirements and other customer- related costs, as well as higher distribution costs from storm repairs and overhead line maintenance all contributed to higher other operating costs, compared to the preceding year. Total accelerated cost recovery under the Company's rate reduction plan and Penn's restructuring plan increased by $23.2 million in 2000 and $160.6 million in 1999, compared to the prior year. The table below summarizes the accelerated cost recovery by income statement caption: Regulatory Plan Accelerations 2000 1999 1998 --------------------------------------------------------------- (In millions) Depreciation and amortization $332.6 $333.3 $172.9 Income tax amortization & other 42.6 18.7 18.5 --------------------------------------------------------------- Total Plan Accelerations $375.2 $352.0 $191.4 =============================================================== The impact of accelerated cost recovery on depreciation and amortization was relatively unchanged in 2000 from the preceding year, but accounted for most of the increase in depreciation and amortization in 1999, compared to 1998. General taxes decreased $14.4 million in 2000 from 1999 primarily due to a prior year gross receipts tax refund, favorable property tax law changes and the phase-out of Pennsylvania's Capital Stock and Franchise Tax. Other Income Other income increased $10.1 million in 2000, compared to the previous year, principally due to the interest earned on long-term notes from ATSI (see Financial Condition, Capital Resources and Liquidity) and short-term loans to other affiliated companies. Net Interest Charges Net interest charges decreased by $19.4 million in 2000 and $12.0 million in 1999, compared to the prior year. We continue to redeem and refinance our outstanding debt and preferred stock, thus maintaining the downward trend in our financing costs during 2000. Net redemptions of long-term debt and preferred stock totaled $121.4 million and refinancings totaled $186.5 million in 2000. Effects of SFAS 71 Discontinuation ---------------------------------- The application of Statement of Financial Accounting Standards No. (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" was discontinued for the Company's generation business effective with approval by the Public Utilities Commission of Ohio (PUCO) of the Ohio transition plan. Beginning June 30, 2000, the Company's balance sheet reflected that discontinuance with $1.2 billion of impaired generating plant investments recognized as regulatory assets which will be recovered as transition costs. We expect the incremental amortization of transition costs in 2001 to be lower than the depreciation and amortization accelerated under our former regulatory plan in 2000. On June 18, 1998, the Pennsylvania Public Utility Commission authorized Penn's rate restructuring plan that resulted in the discontinuation of SFAS 71 to Penn's generation business. Under the plan, Penn's rates were restructured to establish separate charges for transmission and distribution services; generation (which is subject to competition); and stranded cost recovery. A total of $215.4 million of impaired nuclear generating plant investments were recognized as regulatory assets to be recovered through the stranded cost recovery charge. The portion of generating plant investment not recovered through future customer rates resulted in a $30.5 million extraordinary after-tax write-down in 1998. 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. Financial Condition, Capital Resources and Liquidity ---------------------------------------------------- On September 1, 2000, FirstEnergy Corp.'s (FirstEnergy) electric utility operating companies transferred $1.2 billion of their transmission assets to ATSI. As part of the transfer, we sold to ATSI $727.1 million of our transmission assets, net of $339.4 million of accumulated depreciation and $10.9 million of investment tax credits for $169.6 million of cash and $207.2 million of long-term notes. Our improving financial position reflects ongoing efforts to increase competitiveness and enhance shareholder value. We have continued to strengthen our financial position over the past five years by improving our fixed charge coverage ratios. Our corporate indenture ratio, which is used to measure our ability to issue first mortgage bonds, increased from 5.78 in 1995 to 7.45 in 2000, which enhances our financial flexibility. Over the same period, our charter ratio, a measure of our ability to issue preferred stock, improved from 2.31 to 2.88 and our common stockholder's equity as a percentage of capitalization rose from approximately 43% at the end of 1995 to 52% at the end of 2000. Over the last five years, we have reduced the average cost of long-term debt from 8.00% in 1995 to 7.58% at the end of 2000. Net redemptions of long-term debt and preferred stock and long-term debt refinancings completed in 2000 are expected to generate annual savings of about $8 million. We had about $18.3 million of cash and temporary investments and $315.4 million of short-term indebtedness as of December 31, 2000. Our unused borrowing capability included $187.5 million under revolving lines of credit and a $2.0 million bank facility that provides for borrowings on a short-term basis at the bank's discretion. At the end of 2000, we had the capability to issue $1.3 billion of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon the earnings coverage test under our charter, we could issue $1.8 billion of preferred stock (assuming no additional debt was issued). Our cash requirements in 2001 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without issuing new securities. During 2000, we reduced our total debt by approximately $330 million. We have cash requirements of approximately $1.0 billion for the 2001-2005 period to meet scheduled maturities of long-term debt and preferred stock. Of that amount, approximately $23.2 million relates to 2001. Our capital spending for the period 2001-2005 is expected to be about $513 million (excluding nuclear fuel) of which approximately $118 million applies to 2001. Investments for additional nuclear fuel during the 2001-2005 period are estimated to be approximately $187 million, of which about $39 million relates to 2001. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $217 million and $45 million, respectively, as the nuclear fuel is consumed. Also, we have operating lease commitments, net of PNBV Capital Trust cash receipts, of approximately $373 million for the 2001-2005 period, of which approximately $68 million relates to 2001. Moody's Investors Service upgraded our credit ratings on September 27, 2000 and Fitch upgraded our credit ratings on October 30, 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 following table summarizes the changes in credit ratings: Credit Ratings Before Upgrade After Upgrade ------------------------------------------------------------------- Moody's Moody's Investors Investors Service Fitch Service Fitch -------------------------------------------------------------------- OE -- First mortgage bonds Baa2 BBB Baa1 BBB+ Preferred Stock ba1 BB+ baa2 BBB- Penn ---- First mortgage bonds Baa2 BBB+ Baa1 Unchanged Preferred Stock ba1 BBB baa2 Unchanged 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 PNBV 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 -- CEI 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 alternative 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 $250 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 560 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 area. Through February 8, 2001, approximately 409 MW of the 560 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 55,000 of our customers requested generation services from other authorized suppliers, including FirstEnergy Services Corp. (FE Services), an affiliated company. Beginning in 2001, Ohio utilities which 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 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 distribution services. FirstEnergy Generation Corp. (FE Generation), an associated company, leases fossil plants from us and operates those plants. 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. In 1999, we received notification of pending legal actions based on alleged violations of the Clean Air Act at our W. H. Sammis Plant involving the states of New York and Connecticut as well as the U.S. Department of Justice. The civil complaint filed by the U.S. Department of Justice requests installation of "best available control technology" as well as civil penalties of up to $27,500 per day of violation. We believe the Sammis Plant is in full compliance with the Clean Air Act and the legal actions are without merit. However, we are unable to predict the outcome of this litigation. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while the matter is being decided. 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. 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. OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME

OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS

OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION

OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)

OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

CONSOLIDATED STATEMENTS OF PREFERRED STOCK

OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS

OHIO EDISON 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) ================================================================================================= Companies' share of prepaid (accrued) benefit cost $ 213.9 $ 194.8 $(157.0) $(145.7) ================================================================================================= 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 ============================================================================================================== Companies' share of total plan costs $ (19.1) $ (16.9) $ (39.7) $24.7 $25.5 $31.2 ------------------------------------------------------------------------------------------------------------
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 and operating expenses include transactions with CEI and TE, which were primarily for electric sales and ATSI transmission rent expense of $32.4 million starting in 2000. The amounts related to CEI and TE were $53.4 million and $15.9 million, respectively, for 2000, $27.7 million and $18.1 million, respectively, for 1999 and $17.8 million and $12.7 million, respectively, for 1998. Other income included $5.4 million of interest income from ATSI beginning in 2000. FirstEnergy provides support services at cost to the Companies and other affiliated companies, for which the Companies were billed $119.0 million, $118.2 million and $114.2 million in 2000, 1999 and 1998, respectively. SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets. As of December 31, 1999, cash and cash equivalents included $83 million used for the redemption of long-term debt in the first quarter of 2000. The Companies reflect temporary cash investments at cost, which approximates their market value. Noncash financing and investing activities included capital lease transactions amounting to $1.3 million, $1.4 million and $1.6 million for the years 2000, 1999 and 1998, respectively. Commercial paper transactions of OES Fuel, Incorporated (OES Fuel) (a wholly owned subsidiary of the Company) that have initial maturity periods of three months or less are reported net within financing activities under long-term debt and are reflected as long-term debt on the Consolidated Balance Sheets (see Note 3F). 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 $2,205 $2,257 $2,483 $2,459 Preferred stock $ 140 $ 138 $ 145 $ 142 Investments other than cash and cash equivalents: Debt securities - Maturity (5-10 years) $ 460 $ 441 $ 475 $ 476 - Maturity (more than 10 years) 464 512 258 267 Equity securities 13 13 14 14 All other 342 341 301 311 ------------------------------------------------------------------------ $1,279 $1,307 $1,048 $1,068 ======================================================================== The fair values of long-term debt and preferred stock 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 Companies' 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 Companies have no securities held for trading purposes. REGULATORY ASSETS- The Companies recognize, as regulatory assets, costs which the FERC, PUCO and PPUC 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 Companies' respective transition and rate restructuring plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations. The Companies also recognized additional cost recovery of $270 million, $257 million and $50 million in 2000, 1999 and 1998, respectively, as additional regulatory asset amortization in accordance with their regulatory plans. The application of SFAS 71 to the Company's generation business was discontinued effective with the PUCO's approval of FirstEnergy's transition plan. The effect of such discontinuance 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 $1.2 billion for the Company. Regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2000 1999 ----------------------------------------------------------------- (In millions) Impaired generating assets $1,238.1 $ -- Nuclear unit expenses 619.4 643.0 Customer receivables for future income taxes 190.3 455.3 Competitive transition charge 230.9 280.4 Sale and leaseback costs 113.6 120.5 Loss on reacquired debt 80.1 79.7 Employee postretirement benefit costs 20.7 24.8 Other 5.7 14.6 ------------------------------------------------------------------- Total $2,498.8 $1,618.3 =================================================================== 2. LEASES The Companies lease certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. The Company sold portions of its ownership interest in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. During the terms of the leases, the Company continues to be responsible, to the extent of its individual combined ownership and leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company has the right, at the end of the respective basic lease terms, to renew the leases for up to two years. The Company also has 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. The basic rental payments are adjusted when applicable federal tax law changes. OES Finance, Incorporated (OES Finance), a wholly owned subsidiary of the Company, maintains deposits pledged as collateral to secure reimbursement obligations relating to certain letters of credit supporting the Company's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits pledged to the financial institution providing those letters of credit are the sole property of OES Finance. In the event of liquidation, OES Finance, as a separate corporate entity, would have to satisfy its obligations to creditors before any of its assets could be made available to the Company as sole owner of OES Finance common stock. 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, are summarized as follows: 2000 1999 1998 --------------------------------------------------- (In millions) Operating leases Interest element $107.0 $108.5 $110.0 Other 35.1 34.4 28.9 Capital leases Interest element 2.5 5.3 5.3 Other 2.6 4.4 4.8 --------------------------------------------------- Total rentals $147.2 $152.6 $149.0 =================================================== The future minimum lease payments as of December 31, 2000, are: Operating Leases -------------------------------- Capital Lease PNBV Capital Leases Payments Trust Net ---------------------------------------------------------------- (In millions) 2001 $ 5.3 $ 127.1 $ 59.5 $ 67.6 2002 4.8 130.4 61.0 69.4 2003 4.5 136.9 62.6 74.3 2004 4.4 137.7 58.3 79.4 2005 4.4 138.6 56.3 82.3 Years thereafter 8.6 1,551.7 474.6 1,077.1 ------------------------------------------------------------------ Total minimum lease payments 32.0 $2,222.4 $772.3 $1,450.1 Executory costs 10.6 ======== ====== ======== --------------------------- Net minimum lease payments 21.4 Interest portion 8.4 --------------------------- Present value of net minimum lease payments 13.0 Less current portion 2.2 --------------------------- Noncurrent portion $10.8 =========================== The Company invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in the Company's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. The PNBV capital trust arrangement effectively reduces lease costs related to those transactions. 3. CAPITALIZATION: (A) RETAINED EARNINGS- Under the Company's first mortgage indenture, the Company's consolidated retained earnings unrestricted for payment of cash dividends on the Company's common stock were $409.8 million at December 31, 2000. (B) EMPLOYEE STOCK OWNERSHIP PLAN- FirstEnergy funds the matching contribution for its 401(k) savings plan through an ESOP Trust. All of the Companies' full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from the Company and acquired 10,654,114 shares of the Company's common stock (subsequently converted to FirstEnergy common stock) through market purchases. The ESOP loan is included in Other Property and Investments on the Consolidated Balance Sheets as of December 31, 2000 and 1999 as an investment with FirstEnergy related to the FirstEnergy savings plan. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. (C) PREFERRED AND PREFERENCE STOCK- Penn's 7.75% series of preferred stock has a restriction which prevents early redemption prior to July 2003. The Company's 8.45% series of preferred stock has no optional redemption provision. All other preferred stock may be redeemed by the Companies in whole, or in part, with 30-60 days' notice. The Company has eight million authorized and unissued shares of preference stock having no par value. (D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- The Company's 8.45% series of preferred stock has an annual sinking fund requirement for 50,000 shares. Penn's 7.625% series has an annual sinking fund requirement for 7,500 shares beginning on October 1, 2002. The Companies' preferred shares are retired at $100 per share plus accrued dividends. Annual sinking fund requirements are $5 million in 2001 and $1 million in each year 2002-2005. (E) COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES- Ohio Edison Financing Trust, a wholly owned subsidiary of the Company, has issued $120 million of 9% Cumulative Trust Preferred Capital Securities. The Company purchased all of the Trust's Common Securities and simultaneously issued to the Trust $123.7 million principal amount of 9% Junior Subordinated Debentures due 2025 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. 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, amended and restated 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 indentures and their supplements, which secure all of the Companies' first mortgage bonds, serve as direct first mortgage liens on substantially all property and franchises, other than specifically excepted property, owned by the Companies. Based on the amount of bonds authenticated by the Trustees through December 31, 2000, the Companies' annual sinking and improvement fund requirements for all bonds issued under the mortgage amounts to $31 million. The Companies expect to deposit funds in 2001 that will be withdrawn upon the surrender for cancellation of a like principal amount of bonds, which are specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) ---------------------------- 2001 $304.2 2002 515.6 2003 247.7 2004 257.0 2005 135.4 ---------------------------- The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $225.1 million and noncancelable municipal bond insurance policies of $136.5 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letters of credit, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 0.60% to 1.25% of the amounts of the letters of credit to the issuing banks and are obligated to reimburse the banks for any drawings thereunder. The Company had unsecured borrowings of $100 million as of December 31, 2000, supported by a $250 million long-term revolving credit facility agreement which expires November 18, 2002. The Company must pay an annual facility fee of 0.20% on the total credit facility amount. In addition, the credit agreement provides that the Company maintain unused first mortgage bond capability for the full credit agreement amount under the Company's indenture as potential security for the unsecured borrowings. Nuclear fuel purchases are financed through the issuance of OES Fuel commercial paper and loans, both of which are supported by a $180.5 million long-term bank credit agreement which expires March 31, 2001. The Company intends to extend the credit agreement through March 31, 2002. Accordingly, a portion of the commercial paper and loans is reflected as long-term debt on the Consolidated Balance Sheets. OES Fuel must pay an annual facility fee of 0.20% on the total line of credit and an annual commitment fee of 0.0625% on any unused amount. 4. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT: Short-term borrowings outstanding as of December 31, 2000, consisted of $136.4 million of bank borrowings and $159.9 million of OES Capital, Incorporated (OES Capital) commercial paper. OES Capital is a wholly owned subsidiary of the Company whose borrowings are secured by customer accounts receivable. OES Capital can borrow up to $170 million under a receivables financing agreement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.20% on the amount of the entire finance limit. The receivables financing agreement expires in 2002. As of December 31, 2000, the Company also had total short-term borrowings of $19.1 million from its affiliates. The Company has lines of credit with domestic banks that provide for borrowings of up to $55 million under various interest rate options. Short-term borrowings may be made under these lines of credit on its unsecured notes. To assure the availability of these lines, the Company is required to pay annual commitment fees of 0.15% to 0.20%. These lines expire at various times during 2001. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2000 and 1999, were 6.93% and 6.27%, respectively. 5. COMMITMENTS AND CONTINGENCIES: CAPITAL EXPENDITURES- The Companies' current forecasts reflect expenditures of approximately $513 million for property additions and improvements from 2001-2005, of which approximately $118 million is applicable to 2001. Investments for additional nuclear fuel during the 2001-2005 period are estimated to be approximately $187 million, of which approximately $39 million applies to 2001. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $217 million and $45 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 their ownership and leasehold interests in the Beaver Valley Station and the Perry Plant, the Companies' 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 $168.2 million per incident but not more than $19.1 million in any one year for each incident. The Companies are also insured as to their respective interests in Beaver Valley 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 Companies have also obtained approximately $358 million of insurance coverage for replacement power costs for their respective interests in Beaver Valley and Perry. Under these policies, the Companies can be assessed a maximum of approximately $17.7 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 Companies intend 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 Companies' 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 Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs. ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Companies 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 Companies are 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 Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies are 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 Companies' 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 Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a "draft" SIP that requires compliance with the NOx budgets at the Companies' 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 Companies' 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 Companies operate affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against the Companies in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of these proceedings, the Companies believe the Sammis Plant is in full compliance with the Clean Air Act and the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. 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. 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 $644.4 $667.2 $733.9 $681.2 Operating Expenses and Taxes 524.9 533.1 604.6 581.8 ---------------------------------------------------------------------- Operating Income 119.5 134.1 129.3 99.4 Other Income 12.3 11.5 16.4 15.8 Net Interest Charges 51.0 51.8 51.4 47.6 ---------------------------------------------------------------------- Net Income $ 80.8 $ 93.8 $ 94.3 $ 67.6 ====================================================================== Earnings on Common Stock $ 78.0 $ 91.0 $ 91.5 $ 64.8 ====================================================================== March 31, June 30, September 30, December 31, Three Months Ended 1999 1999 1999 1999 ---------------------------------------------------------------------- (In millions) Operating Revenues $633.1 $646.7 $770.5 $636.6 Operating Expenses and Taxes 498.1 532.7 650.2 532.8 ---------------------------------------------------------------------- Operating Income 135.0 114.0 120.3 103.8 Other Income 9.3 13.1 10.2 13.2 Net Interest Charges 56.5 58.4 53.9 52.5 ---------------------------------------------------------------------- Net Income $ 87.8 $ 68.7 $ 76.6 $ 64.5 ====================================================================== Earnings on Common Stock $ 84.9 $ 65.8 $ 73.7 $ 61.7 ====================================================================== Report of Independent Public Accountants To the Stockholders and Board of Directors of Ohio Edison Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Ohio Edison Company (an Ohio corporation and wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries 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 Ohio Edison Company and subsidiaries 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. 24 1