EX-13 10 ex13.txt ANNUAL REPORT - FE Management Report The consolidated financial statements were prepared by the management of FirstEnergy Corp., who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. Arthur Andersen LLP, independent public accountants, have expressed an unqualified opinion on the Company's consolidated financial statements. The Company's internal auditors, who are responsible to the Audit Committee of the Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls. The Audit Committee consists of four nonemployee directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent public accountants and the internal auditors; recommendation to the Board of Directors of independent accountants to conduct the normal annual audit and special purpose audits as may be required; and reporting to the Board of Directors the Committee's findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee also reviews the results of management's programs to monitor compliance with the Company's policies on business ethics and risk management. The Audit Committee held five meetings in 2000. Richard H. Marsh Vice President and Chief Financial Officer Harvey L. Wagner Controller and Chief Accounting Officer Report of Independent Public Accountants To the Stockholders and Board of Directors of FirstEnergy Corp.: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of FirstEnergy Corp. (an Ohio corporation) and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, common stockholders' 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 FirstEnergy Corp. 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. FIRSTENERGY CORP. SELECTED FINANCIAL DATA
For the Years Ended December 31, 2000 1999 1998 1997 1996 ---------------------------------------------------------------------------------------------------- (In thousands, except per share amounts) Revenues $ 7,028,961 $ 6,319,647 $ 5,874,906 $ 2,961,125 $2,521,788 ------------------------------------------------------------- Income Before Extraordinary Item $ 598,970 $ 568,299 $ 441,396 $ 305,774 $ 302,673 ------------------------------------------------------------- Net Income $ 598,970 $ 568,299 $ 410,874 $ 305,774 $ 302,673 ------------------------------------------------------------- Earnings per Share of Common Stock: Before Extraordinary Item $2.69 $2.50 $1.95 $1.94 $2.10 After Extraordinary Item $2.69 $2.50 $1.82 $1.94 $2.10 ------------------------------------------------------------- Dividends Declared per Share of Common Stock $1.50 $1.50 $1.50 $1.50 $1.50 ------------------------------------------------------------- Total Assets $17,941,294 $18,224,047 $18,192,177 $18,261,481 $9,218,623 ------------------------------------------------------------- Capitalization at December 31: Common Stockholders' Equity $ 4,653,126 $ 4,563,890 $ 4,449,158 $ 4,159,598 $2,503,359 Preferred Stock: Not Subject to Mandatory Redemption 648,395 648,395 660,195 660,195 211,870 Subject to Mandatory Redemption 161,105 256,246 294,710 334,864 155,000 Long-Term Debt 5,742,048 6,001,264 6,352,359 6,969,835 2,712,760 ------------------------------------------------------------- Total Capitalization $11,204,674 $11,469,795 $11,756,422 $12,124,492 $5,582,989 ==============================================================
PRICE RANGE OF COMMON STOCK FirstEnergy Corp.'s Common Stock is listed on the New York Stock Exchange and is traded on other registered exchanges.
2000 1999 -------------------------------------------------------------- First Quarter High-Low 23.56 18.00 33.19 27.94 ------------ ------------ Second Quarter High-Low 26.88 20.56 32.13 27.94 ------------ ------------ Third Quarter High-Low 27.88 22.94 31.31 24.75 ------------ ------------ Fourth Quarter High-Low 32.13 24.11 26.56 22.13 ------------ ------------ Yearly High-Low 32.13 18.00 33.19 22.13 -------------------------------------------------------------- Prices are based on reports published in The Wall Street Journal for ----------------------- New York Stock Exchange Composite Transactions.
HOLDERS OF COMMON STOCK There were 167,912 and 166,966 holders of 224,531,580 and 223,981,580 shares of the Company's Common Stock as of December 31, 2000 and January 31, 2001, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 4A. FIRSTENERGY CORP. 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), the availability and cost of capital, inability to accomplish or realize anticipated benefits of strategic goals (including our merger with GPU, Inc.) and other similar factors. Proposed Business Combination ----------------------------- On August 8, 2000, FirstEnergy entered into an agreement to merge with GPU, Inc. (GPU), a Pennsylvania corporation, headquartered in Morristown, New Jersey. Subsequently, the agreement was overwhelmingly approved by the shareholders of both companies. All regulatory filings necessary to complete the merger have since been made. Our target to complete the merger is by the end of the second quarter of 2001. Under the merger agreement, we would acquire all the outstanding shares of GPU's common stock for approximately $4.5 billion in cash and FirstEnergy common stock. Our cash investment would be financed through the issuance of about $2.2 billion of new debt. Also, approximately $7.4 billion of debt and preferred stock of GPU's subsidiaries would remain outstanding. The transaction would be accounted for by the purchase method. The combined company's principal electric utility operating companies would include Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE), Pennsylvania Power Company (Penn) and American Transmission Systems, Incorporated (ATSI), as well as GPU's electric utility operating companies - Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company, which serve customers in Pennsylvania and New Jersey. The merger is expected to provide enhanced opportunities for financial growth, greater scope and size, improved generation efficiency and broadened unregulated opportunities. The combination will provide a significant market for our generating capacity and value-added services and will support our strategic vision of being the premier retail energy and related services provider in our targeted area for growth - a thirteen-state region in the northeastern quadrant of the nation. Competition We continue to face many competitive challenges as consumers are provided increasing opportunities to select their electricity suppliers. As our industry changes to a more competitive environment, we continue to take actions designed to create a larger, stronger enterprise that will be better positioned to compete in the changing energy marketplace. As Ohio approached a new era of customer choice in the selection of energy suppliers, we continued to develop our regionally-focused retail sales strategy. Results of Operations Net income increased to $599.0 million in 2000, compared to $568.3 million in 1999 and $410.9 million in 1998. The increase in 2000 resulted primarily from lower fuel costs and increased generation output, reduced financing costs and gains realized on the sales of emission allowances. In 1999, higher sales revenues, the absence of unusually high purchased power costs experienced in 1998 and lower interest costs contributed to the increase in net income from the prior year. Additional sales by our unregulated businesses resulted in a $709.3 million increase in total revenues in 2000 compared to the prior year. The increase resulted from an expansion of both gas and electric sales. In 1999, the $444.7 million increase in revenues resulted substantially from contributions of the Electric Utility Operating Companies (EUOC) and increases in newly acquired businesses, which were partially offset by reduced revenues from FirstEnergy Trading Services, Inc. (FETS) compared to the prior year's results. The sources of the changes in revenues during 2000 and 1999 are summarized in the following table.
Sources of Revenue Changes 2000 1999 --------------------------------------------------------- Increase (Decrease) (In millions) EUOC: Electric sales $(38.5) $213.2 Other electric utility revenues 6.4 3.1 --------------------------------------------------------- Total EUOC (32.1) 216.3 --------------------------------------------------------- Unregulated Businesses: Retail electric sales 170.7 54.0 FETS 211.5 (220.1) Other businesses 359.2 394.5 --------------------------------------------------------- Total Unregulated Businesses 741.4 228.4 --------------------------------------------------------- Net Revenue Increase $709.3 $444.7 =========================================================
Electric Sales EUOC electric sales revenues decreased by $32.1 million in 2000, compared to 1999, as a result of lower unit prices which were partially offset by increased generation sales volume. Despite a milder summer, retail electric generation sales were 2.0% higher in 2000 than the previous year. Total electric generation sales (including unregulated sales) increased 8.4% in 2000, compared to 1999. Unregulated retail sales more than tripled from the prior year reflecting continued progress in our marketing efforts to expand retail electric sales to our targeted unregulated markets in the eastern seaboard states. Sales to commercial customers accounted for most of the increase. The cooler summer weather reduced retail customer demand, making more of our energy available to serve the wholesale market. As a result, we were able to achieve moderate growth in kilowatt-hour sales to that market in 2000. EUOC kilowatt-hour deliveries (to customers in our franchise areas) increased in 2000 from the prior year due to additional sales to commercial and industrial customers. Kilowatt-hour sales to residential customers declined. Other electric utility revenues increased in 2000 from the previous year primarily due to additional transmission service revenues. EUOC revenues increased $216.3 million in 1999, compared to 1998, benefiting from increases in kilowatt-hour sales, which were only partially offset by reduced unit prices. Retail kilowatt-hour sales increased 2.3%. Total electric generation sales increased 8.0% in 1999 from the prior year due to additional unregulated sales reflecting our initial expansion into targeted eastern markets and weather-induced demand in the wholesale market. EUOC kilowatt-hour deliveries to residential, commercial and industrial customers increased in 1999, compared to 1998, reflecting a strong consumer-driven economy and warmer weather than the preceding year. Changes in electric generation sales and kilowatt-hour deliveries in 2000 and 1999 are summarized in the following table:
Changes in KWH Sales 2000 1999 ---------------------------------------------------------- Increase (Decrease) Electric Generation Sales: EUOC - Retail 2.0% 2.3% Unregulated 50.4% 52.0% ---------------------------------------------------------- Total Electric Generation Sales 8.4% 8.0% ======================================================== EUOC Distribution Deliveries: Residential (1.2)% 5.5% Commercial 2.5% 2.8% Industrial 3.2% 2.5% ---------------------------------------------------------- Total Distribution Deliveries 1.7% 3.4% ==========================================================
Other Sales Retail natural gas revenues were the largest source of increase in other business revenues in 2000, compared to 1999. Collectively, three gas acquisitions in 1999 (Atlas Gas Marketing Inc., Belden Energy Services Company and Volunteer Energy LLC), as well as increased retail marketing efforts, significantly expanded retail gas revenues in 2000. Margins were held down by higher natural gas supply costs but increased activities in our natural gas exploration and production joint venture, Great Lakes Energy Partners, helped to offset the lower gas sales margins. FETS also expanded its wholesale electric and gas revenues in 2000 from prior year levels. In 1999, FETS revenues decreased significantly compared to the prior year because of refocusing its activities on supporting our retail marketing activities. New acquisitions and a one-time gain of $53 million from the sale of a partnership investment contributed to the increase in other business revenues in 1999, compared to 1998. Operating Expenses Total expenses increased $739.8 million in 2000 and $255.5 million in 1999, compared to the prior year, primarily reflecting higher levels of other expenses for EUOC and unregulated operations, offset in part by lower EUOC fuel and purchased power costs. Fuel and purchased power decreased $75.7 million in 2000, compared to 1999. Lower fuel expense accounted for all of the reduction, declining $103.6 million from 1999, despite a 7% increase in output from our generating units. Factors contributing to lower fuel expense in 2000 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 western coal and enhanced the efficiency and cost-competitiveness of our fossil generation fleet. Purchased power costs increased $27.9 million in 2000 from the prior year due to higher average prices and to additional megawatt-hours purchased. In 1999, fuel and purchased power costs were down $106.7 million, compared to 1998. The EUOC purchased power costs accounted for all of the reduction. Much of the improvement was due to the absence in 1999 of unusual conditions experienced in 1998, which resulted in an additional $77.4 million of purchased power costs in that year. The 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 several of our power plants at that time required the EUOC to purchase significant amounts of power on the spot market. Although above normal temperatures were also experienced in 1999, the EUOC maintained a stronger capacity position compared to the previous year and better met customer demand from their own generation resources. Other expenses for the EUOC rose $26.6 million in 2000, compared to 1999, primarily due to additional nuclear refueling costs associated with three refueling outages in 2000 versus two during the previous year and increased nuclear ownership resulting from the Duquesne asset swap. Costs incurred to improve the availability of our fossil generation fleet and leased portable diesel generators, acquired as part of our summer supply strategy, added to other expenses for the EUOC in 2000, compared to 1999. Also, we incurred unusual charges in 2000 for early retirement program costs, as well as increased reserves for potentially uncollectible accounts for customers in the steel sector who are experiencing significant financial pressures from foreign steel competition. Partially offsetting the higher costs were increased gains of $38.5 million realized from the sale of emission allowances in 2000 as well as nonrecurring costs recorded in the prior year. In 1999, other expenses for the EUOC increased from 1998 due to several factors. Similar to 2000, refueling outage costs and incremental expenses related to the asset swap, which occurred in early December 1999, contributed to increase other expenses in 1999 compared to 1998. Additionally, nuclear costs in 1999 included nonrecurring swap-related liabilities assumed. Also contributing to the increase were higher customer, sales and marketing expenses resulting from marketing programs and information system costs; higher distribution expenses from storm damage, as well as line and meter maintenance; and a nonrecurring expense related to a change in employee vacation benefits. Other expenses for unregulated businesses rose $789.6 million in 2000, compared to 1999. FETS contributed to the increase with its other expenses rising in line with its higher revenues, reflecting the continued expansion of its operations to support our retail marketing efforts. FETS expenses were significantly lower in 1999 due to the absence of costs incurred in 1998 associated with credit losses and replacement power costs resulting from the period of sharp price increases in the spot market for electricity in late June 1998. Refocusing FETS activities in 1999 on supporting our retail market activities also reduced expenses from the preceding year. Acquisitions of three natural gas companies in 1999 and a general expansion of unregulated sales activity combined to increase the scope, and therefore, the operating expenses of our unregulated business activities in 2000. Also, increased reserves for potential uncollectible accounts were established for customers in the steel sector. In addition, a $10.5 million reserve was recognized in 2000 for potential construction contract losses. The acquisitions in the facilities services and natural gas businesses, as well as costs attributable to unregulated sales activity, combined to increase other expenses in 1999, compared to the previous year. Depreciation and amortization was reduced by $9.8 million in the second half of 2000, following approval by the Public Utilities Commission of Ohio (PUCO) of the Ohio transition plan (see Outlook). Total accelerated cost recovery in connection with OE's rate reduction plan and Penn's restructuring plan are summarized by income statement caption in the table below:
Regulatory Plan Accelerations 2000 1999 1998 ---------------------------------------------------------------- (In millions) Depreciation and amortization $332.6 $333.3 $172.9 Income tax amortization 42.6 18.7 18.5 ----------------------------------------------------------------- Total Accelerations $375.2 $352.0 $191.4 =================================================================
The impact of OE's rate reduction plan and Penn's restructuring plan on depreciation and amortization was relatively unchanged in 2000 from 1999. In 1999, accelerated cost recovery in connection with the OE rate reduction plan was the primary factor contributing to the increase in depreciation and amortization, compared to 1998. Net Interest Charges We continue to redeem and refinance our outstanding debt and preferred stock, thus maintaining the downward trend in our financing costs during 2000. Interest charges decreased by $43.2 million in 2000 and $28.7 million in 1999, compared to the prior year. Net redemptions of long-term debt and preferred stock totaled $405.9 million and refinancings totaled $284.7 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 OE's generation business and the nonnuclear generation businesses of CEI and TE effective with the PUCO approval of the Ohio transition plan. Beginning June 30, 2000, the balance sheets of our Ohio EUOC reflected that discontinuance with $1.6 billion of impaired generating plant investment recognized as regulatory assets which will be recovered as transition costs. We expect the incremental amortization of transition costs in 2001 for the Ohio EUOC to be lower than the depreciation and amortization accelerated under OE's former regulatory plan in 2000. The application of SFAS 71 to CEI's and TE's nuclear operations was discontinued in connection with the implementation of their regulatory plan in 1997. 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, or $.13 per FirstEnergy common share. The EUOC 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 they continue the application of SFAS 71 to those operations. Capital Resources and Liquidity ------------------------------- We continued to pursue cost efficiencies to fund strategic investments while also strengthening our financial position in 2000. Net security redemptions and refinancings in 2000 should generate annual financing cost savings of about $33 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 EUOC debt ratings during the second half of 2000. Moody's ratings for senior secured debt of OE and Penn were raised from Baa2 to Baa1, and for CEI and TE from Ba1 to Baa3. Fitch's rating for senior secured debt of OE was raised from BBB to BBB+ (Penn's remained at BBB+) and for CEI and TE from BB+ to BBB-. Ratings of many of the junior securities of the EUOC were upgraded to conform to rating relationships typical of investment grade issuers. Those improved ratings should help to enhance our opportunities for further savings in the future. As of December 31, 2000, our common equity as a percentage of capitalization increased to nearly 42% from 38% at the end of 1998. We had approximately $49.3 million of cash and temporary investments and $699.8 million of short-term indebtedness on December 31, 2000. Our unused borrowing capability included $242.5 million under revolving lines of credit. At the end of 2000, the EUOC had the capability to issue $2.7 billion of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests and their respective charters, OE, Penn and TE could issue $2.3 billion of preferred stock (assuming no additional debt was issued). CEI has no restrictions on the issuance of preferred stock. Our cash requirements in 2001 for operating expenses, construction expenditures, scheduled debt maturities, preferred stock redemptions and common stock repurchases are expected to be met without increasing our net debt and preferred stock outstanding. However, our anticipated merger with GPU (see Proposed Business Combination) is expected to require the issuance of approximately $2.2 billion of acquisition-related debt. During 2000, we reduced our total debt by approximately $250.3 million. We have cash requirements of approximately $2.6 billion for the 2001-2005 period to meet scheduled maturities of long-term debt and sinking fund requirements of preferred stock (before giving effect to the GPU acquisition). Of that amount, approximately $193 million applies to 2001. During 2000, we repurchased and retired 7.9 million shares of our common stock at an average price of $24.51 per share. As of December 31, 2000, we had repurchased 12.5 million of the 15 million shares authorized by our Board of Directors under the three-year program, which began in March 1999. Our capital spending (before giving effect to the GPU acquisition) for the period 2001-2005 is expected to be about $3.0 billion (excluding nuclear fuel), of which approximately $683 million applies to 2001. Capital spending in 2001 includes expenditures to complete five combustion turbines expected to provide 425 megawatts (MW) of additional peaking generation capacity to our system by mid-year 2001. Investments for additional nuclear fuel during the 2001-2005 period are estimated to be approximately $380 million, of which about $54 million applies to 2001. During the same period, our nuclear fuel investments are expected to be reduced by approximately $460 million and $100 million, respectively, as the nuclear fuel is consumed. Also, we have operating lease commitments, net of trust cash receipts, of nearly $821 million for the 2001-2005 period, of which approximately $161 million relates to 2001. We invested $4.4 million in 2000 by joining with 20 other leading energy and utility companies (including GPU) to form Pantellos Corporation (Pantellos). Pantellos manages an online, independent marketplace for buyers and sellers from the $130 billion North American utility and energy supply market, which opened for business on January 1, 2001. We expect to realize savings by using the e-market site and to benefit from our ownership interest in this new venture. 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 3, our investments in capital trusts effectively reduce 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.
Comparison of Carrying Value to Fair Value ------------------------------------------------------------------------------------------------- There- Fair 2001 2002 2003 2004 2005 after Total Value ------------------------------------------------------------------------------------------------- (Dollars in millions) Investments other than Cash and Cash Equivalents: Fixed Income $ 87 $ 84 $ 97 $314 $ 58 $1,402 $2,042 $2,086 Average interest rate 5.1% 7.7% 7.7% 7.8% 7.9% 7.4% 7.4% ------------------------------------------------------------------------------------------------- ================================================================================================== Liabilities ------------------------------------------------------------------------------------------------- Long-term Debt: Fixed rate $106 $721 $460 $591 $436 $2,460 $4,774 $4,932 Average interest rate 8.6% 7.9% 8.0% 7.7% 8.8% 7.3% 7.7% Variable rate $ 1 $101 $ 1 $ 1 $ 975 $1,079 $1,078 Average interest rate 8.2% 7.4% 8.0% 8.7% 4.8% 5.1% Short-term Borrowings $700 $ 700 $ 700 Average interest rate 7.9% 7.9% ------------------------------------------------------------------------------------------------- Preferred Stock $ 85 $ 20 $ 2 $ 2 $ 2 $ 135 $ 246 $ 243 Average dividend rate 8.9% 8.9% 7.5% 7.5% 7.5% 8.8% 8.8% ==================================================================================================
Market Risk - Commodity Prices ------------------------------ We are exposed to market risk due to fluctuations in electricity, natural gas, coal and oil prices. To manage the volatility relating to these exposures, we use a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. These derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. We performed a sensitivity analysis to estimate our exposure to the market risk of our commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on both our trading and nontrading instruments would not have had a material effect on our consolidated financial position, results of operations or cash flows as of or for the year ended December 31, 2000. Outlook ------- On July 19, 2000, the PUCO approved our plan for transition to customer choice in Ohio (see Note 1). As part of its authorization, the PUCO approved a settlement agreement between us and major groups representing most of our Ohio customers regarding the transition to customer choice in selection of electricity suppliers. On January 1, 2001, electric choice became available to our Ohio customers. Under the plan, OE, CEI and TE continue to deliver power to homes and businesses through their existing distribution systems, which remain regulated. Their 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, the regulated utility company reduces the customer's bill with a "generation shopping credit," based on the regulated generation component plus an incentive, and the customer receives a generation charge from the alternative supplier. 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 $500 million of transition revenue if the rate of customers (excluding contracts and full-service accounts) switching their service from OE, CEI and TE 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 are also committed under the transition agreement to make available 1,120 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 794 MW of the 1,120 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 our Ohio EUOC had been notified that about 108,000 of their customers requested generation services from other authorized suppliers, including FirstEnergy Services Corp. (FE Services), a wholly owned subsidiary. 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 our regionally-focused retail sales strategy envisions the continued operation of both regulated and competitive operations, our transition plan included details for our corporate separation. The approved plan is consistent with the way we managed our 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 the EUOC continue to provide regulated transmission and distribution services. FirstEnergy Generation Corp. (FE Generation), a wholly owned subsidiary of FE Services, leases fossil and hydroelectric plants from the EUOC and operates those plants. We expect that the transfer of ownership of the EUOC fossil and hydroelectric generating assets to FE Generation will be completed by the end of the market development period. All of the EUOC power supply requirements are provided by FE Services to satisfy the EUOC "provider of last resort" obligation under the transition plan, as well as grandfathered wholesale contracts. The reportable segments in 2000 under SFAS 131, "Disclosures about Segments of an Enterprise and Related Information," reflect the management of these businesses as "Regulated Services" and "Competitive Services." The "Corporate Support Services" is included in "Other." 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. We believe the Sammis Plant is in full compliance with the Clean Air Act and the legal actions are without merit. We are unable, however, 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 Environmental Protection Agency (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 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 6). 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 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. CEI and TE have been named as "potentially responsible parties" (PRPs) 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. CEI and TE have accrued liabilities totaling $3.7 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. CEI and TE believe that waste disposal costs will not have a material adverse effect on their financial condition, cash flows or results of operations. Recently Issued Accounting Standards ------------------------------------ SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recognized on the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative instrument's gains and losses to partially or wholly offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. We adopted SFAS 133, as amended, on January 1, 2001. Prior to adoption, we reviewed all outstanding contracts to determine if they were derivatives or contained embedded derivatives. Derivatives involved in "normal-purchase/normal-sale" transactions were documented and excluded from further treatment under SFAS 133. The remaining derivatives were either documented as cash flow hedges or treated as non-hedge derivatives. In January 2001, we recorded assets and liabilities representing the difference between the derivatives' previous carrying amounts and their fair values under SFAS 133. Related amounts were recorded in net income and comprehensive income. For derivatives that had previously been treated as hedges of forecast transactions, the difference between the derivatives' previous carrying amount and their fair value under SFAS 133 was an adjustment of accumulated other comprehensive income. For derivatives not previously designated as hedges, the difference was an adjustment to net income. These amounts will be reported separately in results for the first quarter of 2001 as a "cumulative effect of a change in accounting principle". The cumulative effect increases assets by $108.3 million, liabilities by $72.6 million and common stockholders' equity by $35.7 million -- other comprehensive income increases by $44.2 million and net income is reduced by $8.5 million. FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2000 1999 1998 ----------------------------------------------------------------------------------------------- (In thousands, except per share amounts) REVENUES: Electric utilities $5,421,668 $5,453,763 $5,237,468 Unregulated businesses 1,607,293 865,884 637,438 ---------- ---------- ---------- Total revenues 7,028,961 6,319,647 5,874,906 ---------- ---------- ---------- EXPENSES: Fuel and purchased power 801,292 876,986 983,735 Other expenses: Electric utilities 1,659,246 1,632,638 1,492,461 Unregulated businesses 1,582,151 792,576 742,778 Provision for depreciation and amortization 933,684 937,976 758,865 General taxes 547,681 544,052 550,908 ---------- ---------- ---------- Total expenses 5,524,054 4,784,228 4,528,747 ---------- ---------- ---------- INCOME BEFORE INTEREST AND INCOME TAXES 1,504,907 1,535,419 1,346,159 ---------- ---------- ---------- NET INTEREST CHARGES: Interest expense 493,473 509,169 542,819 Allowance for borrowed funds used during construction and capitalized interest (27,059) (13,355) (7,642) Subsidiaries' preferred stock dividends 62,721 76,479 65,799 ---------- ---------- ---------- Net interest charges 529,135 572,293 600,976 ---------- ---------- ---------- INCOME TAXES 376,802 394,827 303,787 ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 598,970 568,299 441,396 EXTRAORDINARY ITEM (NET OF INCOME TAX BENEFIT OF $21,208,000) (Note 1) -- -- (30,522) ---------- ---------- ---------- NET INCOME $ 598,970 $ 568,299 $ 410,874 ========== ========== ========== WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 222,444 227,227 226,373 ======= ======= ======= BASIC AND DILUTED EARNINGS PER SHARE OF COMMON STOCK (Note 4C): Income before extraordinary item $2.69 $2.50 $1.95 Extraordinary item (Net of income taxes) (Note 1) -- -- (.13) ----- ----- ----- Net income $2.69 $2.50 $1.82 ===== ===== ===== DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $1.50 $1.50 $1.50 ===== ===== ===== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS
As of December 31, 2000 1999 ----------------------------------------------------------------------------------------------- (In thousands) ASSETS CURRENT ASSETS: Cash and cash equivalents $ 49,258 $ 111,788 Receivables- Customers (less accumulated provisions of $15,800,000 and $6,719,000, respectively, for uncollectible accounts) 399,242 322,687 Other (less accumulated provisions of $20,486,000 and $5,359,000, respectively, for uncollectible accounts) 519,207 445,242 Materials and supplies, at average cost-- Owned 171,563 154,834 Under consignment 112,155 99,231 Prepayments and other 189,869 167,894 ----------- ----------- 1,441,294 1,301,676 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT: In service 12,417,684 14,645,131 Less--Accumulated provision for depreciation 5,263,483 5,919,170 ----------- ----------- 7,154,201 8,725,961 Construction work in progress 420,875 367,380 ----------- ----------- 7,575,076 9,093,341 ----------- ----------- INVESTMENTS: Capital trust investments (Note 3) 1,223,794 1,281,834 Nuclear plant decommissioning trusts 584,288 543,694 Letter of credit collateralization (Note 3) 277,763 277,763 Other 669,057 599,443 ---------- ------------ 2,754,902 2,702,734 ----------- ------------ DEFERRED CHARGES: Regulatory assets 3,727,662 2,543,427 Goodwill 2,088,770 2,129,902 Other 353,590 452,967 ----------- ----------- 6,170,022 5,126,296 ----------- ----------- $17,941,294 $18,224,047 =========== =========== LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt and preferred stock $ 536,482 $ 762,520 Short-term borrowings (Note 5) 699,765 417,819 Accounts payable 478,661 360,379 Accrued taxes 409,640 409,724 Accrued interest 116,544 125,397 Other 352,713 301,572 ----------- ----------- 2,593,805 2,377,411 ----------- ----------- CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholders' equity 4,653,126 4,563,890 Preferred stock of consolidated subsidiaries-- Not subject to mandatory redemption 648,395 648,395 Subject to mandatory redemption 41,105 136,246 Ohio Edison obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Ohio Edison subordinated debentures 120,000 120,000 Long-term debt 5,742,048 6,001,264 ----------- ----------- 11,204,674 11,469,795 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes 2,094,107 2,231,265 Accumulated deferred investment tax credits 241,005 269,083 Nuclear plant decommissioning costs 598,985 562,295 Other postretirement benefits 544,541 498,184 Other 664,177 816,014 ----------- ----------- 4,142,815 4,376,841 ----------- ----------- COMMITMENTS AND CONTINGENCIES (Notes 3 and 6) ----------- ----------- $17,941,294 $18,224,047 =========== =========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2000 1999 -------------------------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) COMMON STOCKHOLDERS' EQUITY: Common stock, $.10 par value - authorized 375,000,000 shares 224,531,580 and 232,454,287 shares outstanding, respectively $ 22,453 $ 23,245 Other paid-in capital 3,531,821 3,722,375 Accumulated other comprehensive income (loss)(Note 4H) 593 (195) Retained earnings (Note 4A) 1,209,991 945,241 Unallocated employee stock ownership plan common stock- 5,952,032 and 6,778,905 shares, respectively (Note 4B) (111,732) (126,776) ----------- ----------- Total common stockholders' equity 4,653,126 4,563,890 ----------- ----------- Number of Shares Optional Outstanding Redemption Price ---------------- --------------------- 2000 1999 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES (Note 4D): Ohio Edison Company (OE) Cumulative, $100 par value- Authorized 6,000,000 shares Not Subject to Mandatory Redemption: 3.90% 152,510 152,510 $ 103.63 $ 15,804 15,251 15,251 4.40% 176,280 176,280 108.00 19,038 17,628 17,628 4.44% 136,560 136,560 103.50 14,134 13,656 13,656 4.56% 144,300 144,300 103.38 14,917 14,430 14,430 --------- --------- -------- ----------- ----------- 609,650 609,650 63,893 60,965 60,965 --------- --------- -------- ----------- ----------- Cumulative, $25 par value- Authorized 8,000,000 shares Not Subject to Mandatory Redemption: 7.75% 4,000,000 4,000,000 25.00 100,000 100,000 100,000 --------- --------- -------- ----------- ----------- Total Not Subject to Mandatory Redemption 4,609,650 4,609,650 $163,893 160,965 160,965 ========= ========= ======== ----------- ----------- Cumulative, $100 par value- Subject to Mandatory Redemption (Note 4E): 8.45% 50,000 100,000 5,000 10,000 Redemption Within One Year (5,000) (5,000) --------- --------- ----------- ----------- 50,000 100,000 -- 5,000 ========= ========= ----------- ----------- Pennsylvania Power Company Cumulative, $100 par value- Authorized 1,200,000 shares Not Subject to Mandatory Redemption: 4.24% 40,000 40,000 103.13 $ 4,125 4,000 4,000 4.25% 41,049 41,049 105.00 4,310 4,105 4,105 4.64% 60,000 60,000 102.98 6,179 6,000 6,000 7.75% 250,000 250,000 -- -- 25,000 25,000 --------- --------- -------- ----------- ----------- Total Not Subject to Mandatory Redemption 391,049 391,049 $ 14,614 39,105 39,105 ========= ========= ======== ----------- ----------- Subject to Mandatory Redemption: 7.625% 150,000 150,000 105.34 $ 15,801 15,000 15,000 ========= ========= ======== ----------- -----------
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31, 2000 1999 ------------------------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) Number of Shares Optional Outstanding Redemption Price ---------------- -------------------- 2000 1999 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES (Cont'd) Cleveland Electric Illuminating Company Cumulative, without par value- Authorized 4,000,000 shares Not Subject to Mandatory Redemption: $ 7.40 Series A 500,000 500,000 $ 101.00 $ 50,500 $ 50,000 $ 50,000 $ 7.56 Series B 450,000 450,000 102.26 46,017 45,071 45,071 Adjustable Series L 474,000 474,000 100.00 47,400 46,404 46,404 $42.40 Series T 200,000 200,000 500.00 100,000 96,850 96,850 --------- --------- -------- ----------- ----------- Total Not Subject to Mandatory Redemption 1,624,000 1,624,000 $243,917 238,325 238,325 ========= ========= ======== ----------- ----------- Subject to Mandatory Redemption: $ 7.35 Series C 80,000 90,000 101.00 $ 8,080 8,041 9,110 $88.00 Series E -- 3,000 -- -- -- 3,000 $91.50 Series Q 10,716 21,430 1,000.00 10,716 10,716 21,430 $88.00 Series R 50,000 50,000 -- -- 51,128 55,000 $90.00 Series S 36,500 55,250 -- -- 36,686 61,170 --------- --------- -------- ----------- ----------- 177,216 219,680 18,796 106,571 149,710 Redemption Within One Year (80,466) (33,464) --------- --------- -------- ----------- ----------- Total Subject to Mandatory Redemption 177,216 219,680 $ 18,796 26,105 116,246 ========= ========= ======== ----------- ----------- Toledo Edison Company Cumulative, $100 par value- Authorized 3,000,000 shares Not Subject to Mandatory Redemption: $ 4.25 160,000 160,000 104.63 $ 16,740 16,000 16,000 $ 4.56 50,000 50,000 101.00 5,050 5,000 5,000 $ 4.25 100,000 100,000 102.00 10,200 10,000 10,000 $ 8.32 100,000 100,000 102.46 10,246 10,000 10,000 $ 7.76 150,000 150,000 102.44 15,366 15,000 15,000 $ 7.80 150,000 150,000 101.65 15,248 15,000 15,000 $10.00 190,000 190,000 101.00 19,190 19,000 19,000 --------- --------- -------- ----------- ----------- 900,000 900,000 92,040 90,000 90,000 --------- --------- -------- ----------- ----------- Cumulative, $25 par value- Authorized 12,000,000 shares Not Subject to Mandatory Redemption: $2.21 1,000,000 1,000,000 25.25 25,250 25,000 25,000 $2.365 1,400,000 1,400,000 27.75 38,850 35,000 35,000 Adjustable Series A 1,200,000 1,200,000 25.00 30,000 30,000 30,000 Adjustable Series B 1,200,000 1,200,000 25.00 30,000 30,000 30,000 --------- --------- -------- ----------- ----------- 4,800,000 4,800,000 124,100 120,000 120,000 --------- --------- -------- ----------- ----------- Total Not Subject to Mandatory Redemption 5,700,000 5,700,000 $216,140 210,000 210,000 ========= ========= ======== ----------- ----------- OE OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY OE SUBORDINATED DEBENTURES (Note 4F): Cumulative, $25 par value- Authorized 4,800,000 shares Subject to Mandatory Redemption: 9.00% 4,800,000 4,800,000 120,000 120,000 ========= ========= ----------- -----------
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
LONG-TERM DEBT (Note 4G) (Interest rates reflect weighted average rates) (In thousands) -------------------------------------------------------------------------------------------------------------------------------- FIRST MORTGAGE BONDS SECURED NOTES UNSECURED NOTES TOTAL -------------------------------------------------------------------------------------------------------------------------------- As of December 31, 2000 1999 2000 1999 2000 1999 2000 1999 ---- ---- ---- ---- ---- ---- ---- ---- Ohio Edison Co. - Due 2000-2005 7.89% $ 509,265 $ 589,265 7.53% $ 232,691 $ 316,623 5.75% $541,725 $ 742,225 Due 2006-2010 -- -- -- 7.74% 7,483 2,062 -- -- -- Due 2011-2015 -- -- -- 6.17% 59,000 40,000 -- -- -- Due 2016-2020 -- -- -- 7.05% 60,000 86,000 -- -- -- Due 2021-2025 7.99% 219,460 219,460 7.00% 69,943 69,943 -- -- -- Due 2026-2030 -- -- -- 5.48% 180,134 119,734 -- -- -- Due 2031-2035 -- -- -- 5.09% 71,900 14,800 -- -- -- ---------- ---------- ---------- ---------- -------- ---------- ----------- ----------- Total-Ohio Edison 728,725 808,725 681,151 649,162 541,725 742,225 $ 1,951,601 $ 2,200,112 ---------- ---------- ---------- ---------- -------- ---------- ----------- ----------- Cleveland Electric Illuminating Co. - Due 2000-2005 8.53% 595,000 595,000 7.85% 384,650 559,680 5.58% 27,700 27,700 Due 2006-2010 6.86% 125,000 125,000 7.29% 271,670 271,670 -- -- -- Due 2011-2015 -- -- -- 6.87% 118,535 118,535 -- -- -- Due 2016-2020 -- -- -- 6.88% 553,355 553,355 -- -- -- Due 2021-2025 9.00% 150,000 150,000 7.70% 226,450 226,450 -- -- -- Due 2026-2030 -- -- -- 4.80% 110,888 110,888 -- -- -- Due 2031-2035 -- -- -- -- -- -- -- -- -- ---------- ---------- ---------- ---------- -------- ---------- ----------- ----------- Total-Cleveland Electric 870,000 870,000 1,665,548 1,840,578 27,700 27,700 2,563,248 2,738,278 ---------- ---------- ---------- ---------- -------- ---------- ----------- ----------- Toledo Edison Co. - Due 2000-2005 7.90% 179,525 179,925 8.06% 190,400 266,000 7.28% 226,100 226,130 Due 2006-2010 -- -- -- 7.13% 30,000 30,000 10.00% 820 820 Due 2011-2015 -- -- -- -- -- -- -- -- -- Due 2016-2020 -- -- -- 7.69% 99,000 166,300 -- -- -- Due 2021-2025 -- -- -- 7.39% 148,000 111,600 -- -- -- Due 2026-2030 -- -- -- 5.90% 13,851 13,851 -- -- -- Due 2031-2035 -- -- -- 5.15% 30,900 -- -- -- -- ---------- ---------- ---------- ---------- -------- ---------- ----------- ----------- Total-Toledo Edison 179,525 179,925 512,151 587,751 226,920 226,950 918,596 994,626 ---------- ---------- ---------- ---------- -------- ---------- ----------- ----------- Pennsylvania Power Co. - Due 2000-2005 7.19% 79,370 80,344 -- -- 28,200 5.90% 5,200 5,200 Due 2006-2010 9.74% 4,870 4,870 -- -- -- -- -- -- Due 2011-2015 9.74% 4,870 4,870 5.40% 1,000 1,000 -- -- -- Due 2016-2020 9.74% 3,929 3,929 6.28% 45,325 45,325 -- -- -- Due 2021-2025 8.33% 33,750 33,750 6.68% 27,182 27,182 -- -- -- Due 2026-2030 -- -- -- 6.10% 47,972 47,972 -- -- -- Due 2031-2035 -- -- -- -- -- -- -- -- -- ---------- ---------- ---------- ---------- -------- ---------- ----------- ----------- Total-Penn Power 126,789 127,763 121,479 149,679 5,200 5,200 253,468 282,642 ---------- ---------- ---------- ---------- -------- ---------- ----------- ----------- OES Fuel -- -- 7.10% 91,620 81,260 -- -- -- 91,620 81,260 Bay Shore Power -- -- 6.60% 147,500 147,500 -- -- -- 147,500 147,500 MARBEL Energy Corp. -- -- -- -- -- 9.37% 638 692 638 692 Facilities Services Group -- -- 6.53% 17,601 14,782 7.29% -- 1,887 17,601 16,669 ---------- ---------- ---------- ---------- -------- --------- ----------- ----------- Total $1,905,039 $1,986,413 $3,237,050 $3,470,712 $802,183 $1,004,654 5,944,272 6,461,779 ========== ========== ========== ========== ======== ========== ----------- ----------- Capital lease obligations 163,242 158,303 ----------- ----------- Net unamortized premium on debt 85,550 105,238 ----------- ----------- Long-term debt due within one year (451,016) (724,056) ----------- ----------- Total long-term debt 5,742,048 6,001,264 ----------- ----------- TOTAL CAPITALIZATION $11,204,674 $11,469,795 -------------------------------------------------------------------------------------------------------------------------------- The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
Accumulated Unallocated Other Other ESOP Comprehensive Number Par Paid-In Comprehensive Retained Common Income of Shares Value Capital Income (Loss) Earnings Stock ------------- --------- ----- ------- ------------- -------- ----------- (Dollars in thousands) Balance, January 1, 1998 230,207,141 $23,021 $3,637,522 $(614) $ 646,646 $(146,977) Net income $410,874 410,874 Minimum liability for unfunded retirement benefits, net of $53,000 of income taxes 175 175 -------- Comprehensive income $411,049 ======== Business acquisitions 6,861,946 686 203,496 Allocation of ESOP Shares 5,495 7,945 Cash dividends on common stock (339,111) ----------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 1998 237,069,087 23,707 3,846,513 (439) 718,409 (139,032) Net income $568,299 568,299 Minimum liability for unfunded retirement benefits, net of $160,000 of income taxes 244 244 -------- Comprehensive income $568,543 ======== Reacquired common stock (4,614,800) (462) (129,671) Centerior acquisition adjustment (468) Allocation of ESOP Shares 6,001 12,256 Cash dividends on common stock (341,467) ---------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 1999 232,454,287 23,245 3,722,375 (195) 945,241 (126,776) Net income $598,970 598,970 Minimum liability for unfunded retirement benefits, net of $(85,000) of income taxes (134) (134) Unrealized gain on investment of securities available for sale 922 922 -------- Comprehensive income $599,758 ======== Reacquired common stock (7,922,707) (792) (194,210) Allocation of ESOP Shares 3,656 15,044 Cash dividends on common stock (334,220) ---------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000 224,531,580 $22,453 $3,531,821 $ 593 $1,209,991 $(111,732) ==============================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to Mandatory Redemption Mandatory Redemption -------------------- ------------------- Par or Par or Number Stated Number Stated of Shares Value of Shares Value --------- ------ --------- ------ (Dollars in thousands) ------------------------------------------------------------------------------------------- Balance, January 1, 1998 12,442,699 $660,195 5,469,408 $356,243 Redemptions- 8.45% Series (50,000) (5,000) $ 7.35 Series C (10,000) (1,000) $88.00 Series E (3,000) (3,000) $91.50 Series Q (10,714) (10,714) $9.375 Series (16,650) (1,665) ------------------------------------------------------------------------------------------- Balance, December 31, 1998 12,442,699 660,195 5,379,044 334,864 Redemptions- 7.64% Series (60,000) (6,000) 8.00% Series (58,000) (5,800) 8.45% Series (50,000) (5,000) $ 7.35 Series C (10,000) (1,000) $88.00 Series E (3,000) (3,000) $91.50 Series Q (10,714) (10,714) $90.00 Series S (18,750) (18,750) $9.375 Series (16,900) (1,690) ------------------------------------------------------------------------------------------- Balance, December 31, 1999 12,324,699 648,395 5,269,680 294,710 Redemptions- 8.45% Series (50,000) (5,000) $ 7.35 Series C (10,000) (1,000) $88.00 Series E (3,000) (3,000) $91.50 Series Q (10,714) (10,714) $90.00 Series S (18,750) (18,750) Amortization of fair market value adjustments- $ 7.35 Series C (69) $88.00 Series R (3,872) $90.00 Series S (5,734) ------------------------------------------------------------------------------------------- Balance, December 31, 2000 12,324,699 $648,395 5,177,216 $246,571 ============================================================================================ The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 598,970 $ 568,299 $ 410,874 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 933,684 937,976 758,865 Nuclear fuel and lease amortization 113,330 104,928 94,348 Other amortization, net (11,635) (10,730) (13,007) Deferred income taxes, net (79,429) (45,054) (23,763) Investment tax credits, net (30,732) (19,661) (22,070) Extraordinary item -- -- 51,730 Receivables (150,520) (203,567) 35,515 Materials and supplies (29,653) 19,631 (14,235) Accounts payable 118,282 82,578 (73,205) Other 45,529 53,906 (49,727) ---------- ---------- ---------- Net cash provided from operating activities 1,507,826 1,488,306 1,155,325 ---------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Common stock -- -- 204,182 Long-term debt 307,512 364,832 499,975 Ohio Schools Council prepayment program -- -- 116,598 Short-term borrowings, net 281,946 163,327 -- Redemptions and Repayments- Common stock 195,002 130,133 -- Preferred stock 38,464 52,159 21,379 Long-term debt 901,764 847,006 804,780 Short-term borrowings, net -- -- 48,354 Common Stock Dividend Payments 334,220 341,467 339,111 ---------- ---------- ---------- Net cash used for financing activities 879,992 842,606 392,869 ---------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions 587,618 624,901 652,852 Cash investments (17,449) (41,213) 47,804 Other 120,195 28,022 82,239 ---------- ---------- ---------- Net cash used for investing activities 690,364 611,710 782,895 ---------- ---------- ---------- Net increase (decrease) in cash and cash equivalents (62,530) 33,990 (20,439) Cash and cash equivalents at beginning of year 111,788 77,798 98,237 ---------- ---------- ---------- Cash and cash equivalents at end of year $ 49,258 $ 111,788 $ 77,798 ========== ========== ========== SUPPLEMENTAL CASH FLOWS INFORMATION: Cash Paid During the Year- Interest (net of amounts capitalized) $ 485,374 $ 520,072 $ 536,064 Income taxes $ 512,182 $ 441,067 $ 326,268 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31, 2000 1999 1998 -------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: Real and personal property $ 281,374 $ 276,227 $ 292,503 State gross receipts 221,385 220,117 217,633 Social security and unemployment 39,134 37,019 27,363 Other 5,788 10,689 13,409 ---------- ---------- ---------- Total general taxes $ 547,681 $ 544,052 $ 550,908 ========== ========== ========== PROVISION FOR INCOME TAXES: Currently payable- Federal $ 467,045 $ 433,872 $ 313,960 State 19,918 25,670 14,452 ---------- ---------- ---------- 486,963 459,542 328,412 ---------- ---------- ---------- Deferred, net- Federal (60,831) (36,021) (14,259) State (18,598) (9,033) (9,504) ---------- ---------- ---------- (79,429) (45,054) (23,763) ---------- ---------- ---------- Investment tax credit amortization (30,732) (19,661) (22,070) ---------- ---------- ---------- Total provision for income taxes $ 376,802 $ 394,827 $ 282,579 ========== ========== ========== RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes $ 975,772 $ 963,126 $ 693,453 ========== ========== ========== Federal income tax expense at statutory rate $ 341,520 $ 337,094 $ 242,709 Increases (reductions) in taxes resulting from- Amortization of investment tax credits (30,732) (19,661) (22,070) State income taxes, net of federal income tax benefit 1,133 10,814 3,216 Amortization of tax regulatory assets 38,702 23,908 28,915 Amortization of goodwill 18,420 19,341 17,868 Preferred stock dividends 18,172 22,988 19,250 Other, net (10,413) 343 (7,309) ---------- ---------- ---------- Total provision for income taxes $ 376,802 $ 394,827 $ 282,579 ========== ========== ========== ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences $1,245,297 $1,878,904 $1,938,735 Deferred nuclear expense 408,771 421,837 436,601 Impaired generating assets 565,893 -- -- Customer receivables for future income taxes 62,527 159,577 159,526 Competitive transition charge 95,497 115,277 135,730 Deferred sale and leaseback costs (128,298) (129,775) (61,506) Unamortized investment tax credits (85,641) (96,036) (102,085) Unused alternative minimum tax credits (32,215) (101,185) (190,781) Other (37,724) (17,334) (33,356) ---------- ---------- ---------- Net deferred income tax liability $2,094,107 $2,231,265 $2,282,864 ========== ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include FirstEnergy Corp. (Company) and its principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power Company (Penn) and The Toledo Edison Company (TE). These utility subsidiaries are referred to throughout as "Companies." On September 1, 2000, the Companies transferred their transmission assets to the Company's wholly owned subsidiary, American Transmission Systems, Inc. (ATSI). As a result, ATSI owns and operates the Company's major high-voltage transmission facilities and has interconnections with other regional utilities. The consolidated financial statements also include the Company's other principal subsidiaries: FirstEnergy Services Corp. (FE Services); FirstEnergy Facilities Services Group, LLC (FE Facilities); FirstEnergy Trading Services, Inc. (FETS), which merged into FE Services on January 1, 2001; and MARBEL Energy Corporation (MARBEL). FE Services provides energy-related products and services primarily on a regional basis and has two subsidiaries, Penn Power Energy, Inc., which provides electric generation services and other energy services to Pennsylvania customers and FirstEnergy Generation Corp., which operates the nonnuclear generation businesses of the Companies. FE Facilities is the parent company of several heating, ventilating, air conditioning and energy management companies. FETS had primarily acquired and arranged for the delivery of electricity and natural gas to FE Services' retail customers. MARBEL is a fully integrated natural gas company. Significant intercompany transactions have been eliminated. The Companies follow the accounting policies and practices prescribed by the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Certain prior year amounts have been reclassified to conform with the current year presentation. REVENUES- The Companies' principal business is providing electric service to customers in central and northern Ohio and western Pennsylvania. The Companies' retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service through the end of the year. Receivables from customers include sales to residential, commercial and industrial customers located in the Companies' service area and sales to wholesale customers. There was no material concentration of receivables at December 31, 2000 or 1999, with respect to any particular segment of the Companies' customers. CEI and TE sell substantially all of their retail customer receivables to Centerior Funding Corp. (CFC), a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust under an asset- backed securitization agreement. The trust completed a public sale of $150 million and private sales of $50 million of receivables-backed investor certificates in 1996 and 2000, respectively, in transactions that qualified for sale accounting treatment. CFC's retained interest in the pool of receivables held by the trust (15.15% as of December 31, 2000) is stated at fair value, reflecting adjustments for anticipated credit losses. Collections of receivables previously transferred to the trust used to purchase new receivables from CFC during 2000, totaled approximately $2.5 billion. Expenses associated with the factoring discount related to the sale of receivables were $13 million in 2000. As of December 31, 2000, receivables recorded on the Consolidated Balance Sheet were reduced by $193 million due to these sales. REGULATORY PLANS- The PUCO approved OE's Rate Reduction and Economic Development Plan in 1995 and FirstEnergy's Rate Reduction and Economic Development Plan for CEI and TE in January 1997. These regulatory plans were to maintain then current base electric rates for OE, CEI and TE through December 31, 2005. At the end of the regulatory plan periods, OE base rates were to be reduced by $300 million (approximately 20 percent below then current levels) and CEI and TE base rates were to be reduced by a combined $310 million (approximately 15 percent below then current levels). The plans also revised the Companies' fuel cost recovery methods so that OE's, CEI's and TE's fuel rates would be frozen through the regulatory plan period, subject to limited periodic adjustments. As part of OE's and FirstEnergy's regulatory plans, transition rate credits were implemented for customers, which were expected to reduce operating revenues for OE by approximately $600 million and CEI and TE by approximately $391 million during the regulatory plan period. The regulatory plans were terminated at the end of 2000 concurrent with the implementation of the FirstEnergy transition plan as described further below. In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provides for a five percent reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005. The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. The Company, on behalf of its Ohio electric utility operating companies -- OE, CEI and TE -- filed its transition plan under Ohio's new electric utility restructuring law in late 1999. The filing also included additional information on FirstEnergy's plans to turn over control, and perhaps ownership, of its transmission assets to the Alliance Regional Transmission Organization. The transition plan itemized, or unbundled, the current price of electricity into its component elements -- including generation, transmission, distribution and transition charges. As required by the PUCO's rules, the Company's transition plan also included its proposals on corporate separation of its regulated and unregulated operations, operational and technical support changes needed to accommodate customer choice, an education program to inform customers of their options under the new law, and how the Company's transmission system will be operated to ensure access to all users. Customer prices would be frozen through a five-year market development period (2001-2005), except for certain limited statutory exceptions including the five percent reduction in the price of generation for residential customers. The plan proposed recovery of generation-related transition costs of approximately $4.5 billion ($4.0 billion, net of deferred income taxes) and transition costs related to regulatory assets aggregating approximately $4.2 billion ($2.9 billion, net of deferred income taxes). On July 19, 2000, the PUCO approved the Company's transition plan as modified by a settlement agreement with major parties to the transition plan. Major parties to the settlement agreement included the PUCO staff, the Ohio Consumers' Counsel, the Industrial Energy Users-Ohio, certain power marketers and others. Major provisions of the settlement agreement consisted of approval of recovery of transition costs in the amounts filed in the transition plan through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The Company will also give preferred access over the Company's subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 megawatts of generation capacity through 2005 at established prices for sales to the Ohio operating companies' retail customers. The base electric rates for distribution service for OE, CEI and TE under their prior respective regulatory plans will be extended from December 31, 2005 through December 31, 2007. The transition rate credits for customers under their prior regulatory plans will also be extended through the Companies' respective transition cost recovery periods. The application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), to OE's generation business and the nonnuclear generation businesses of CEI and TE was discontinued with the issuance of the PUCO transition plan order. The Securities and Exchange Commission (SEC) issued interpretive guidance regarding asset impairment measurement that concluded any supplemental regulated cash flows such as a competitive transition charge (CTC) should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance $1.6 billion of impaired plant investments ($1.2 billion, $304 million and $53 million for OE, CEI and TE, respectively) were recognized as regulatory assets recoverable as transition costs through future regulatory cash flows. The settlement agreement provides to the Company's Ohio customers an additional incentive applied to the generation shopping credit of 45% for residential customers, 30% for commercial customers and 15% for industrial customers as reductions from their bills, when they select alternative energy providers (the credits exceed the price the Company will be offering to electricity suppliers relating to the 1,120 megawatts described in a previous paragraph). The amount of the incentive will serve to reduce the amortization of transition costs during the market development period and will be recovered over the remaining transition cost recovery periods. If the customer switching targets established in the settlement agreement are not achieved by the end of 2005, the transition cost recovery periods could be shortened for OE, CEI and TE to reduce recovery by as much as $500 million (OE-$250 million, CEI-$170 million and TE-$80 million), but any such adjustment would be computed on a class-by-class and pro-rata basis. In June 1998, the PPUC authorized a rate restructuring plan for Penn which essentially resulted in the deregulation of Penn's generation business as of June 30, 1998. Penn was required to remove from its balance sheet all regulatory assets and liabilities related to its generation business and assess all other assets for impairment. In accordance with the SEC guidance, Penn reduced its nuclear generating unit investments by approximately $305 million, of which approximately $227 million was recognized as a regulatory asset to be recovered through a CTC over a seven-year transition period; the remaining net amount of $78 million was written off. The charge of $51.7 million ($30.5 million after income taxes) for discontinuing the application of SFAS 71 to Penn's generation business was recorded as a 1998 extraordinary item on the Consolidated Statement of Income. All of the Companies' regulatory assets will continue to be recovered under provisions of the Ohio transition plan and the Pennsylvania rate restructuring plan. Under the previous regulatory plan, the PUCO had authorized OE to recognize additional capital recovery related to its generating assets (which was reflected as additional depreciation expense) and additional amortization of regulatory assets during the prior regulatory plan period of at least $2 billion, and the PPUC had authorized Penn to accelerate at least $358 million, more than the amounts that would have been recognized if the prior regulatory plans were not in effect. These additional amounts are being recovered through current rates. As of December 31, 2000, OE's and Penn's cumulative additional capital recovery and regulatory asset amortization amounted to $1.424 billion (including Penn's impairment discussed above and CTC recovery). CEI and TE recognized a fair value purchase accounting adjustment of $2.55 billion in connection with the FirstEnergy merger; that fair value adjustment recognized for financial reporting purposes satisfied the $2 billion asset reduction commitment contained in the CEI and TE regulatory plan. For regulatory purposes, CEI and TE recognized the accelerated amortization over the period that their rate plan was in effect. Application of SFAS 71 was discontinued in 1997 with respect to CEI's and TE's nuclear operations (see "Regulatory Assets" below); in 1998 with respect to Penn's generation operations (as described above) and in mid-2000, as discussed above, with respect to OE's generation business and the nonnuclear generation businesses of CEI and TE effective with the issuance of the PUCO transition plan order. The following summarizes net assets included in property, plant and equipment relating to operations for which the application of SFAS 71 was discontinued, compared with the respective company's total assets as of December 31, 2000.
SFAS 71 Discontinued Net Assets Total Assets ------------ ------------ (In millions) OE $1,075 $7,422 CEI 1,556 5,965 TE 623 2,652 Penn 92 989
PROPERTY, PLANT AND EQUIPMENT- Property, plant and equipment reflects original cost (except for the Companies' nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs. The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for OE's electric plant was approximately 2.8% in 2000 and 3.0% in 1999 and 1998. The annual composite rate for Penn's electric plant was approximately 2.6% in 2000, 2.5% in 1999 and 3.0% in 1998. CEI's and TE's composite rates were both approximately 3.4% in 2000, 1999 and 1998. In addition to the straight-line depreciation recognized in 2000, 1999 and 1998, OE and Penn recognized additional capital recovery of $105 million, $95 million and $141 million (excluding Penn's impairment), respectively, as depreciation expense in accordance with their regulatory plans. These amounts were included in the 2000 transfer of accumulated depreciation included in OE's impaired plant investment recognized as regulatory assets as discussed in "Regulatory Plans" above. Annual depreciation expense in 2000 included approximately $29.3 million for future decommissioning costs applicable to the Companies' ownership and leasehold interests in four nuclear generating units. Annual decommissioning costs will increase by approximately $66 million from implementing the Ohio utilities' transition plan in 2001. The Companies' future decommissioning costs reflect the 1999 increase in their ownership interests related to the exchange of certain generating assets with Duquesne Light Company. The Companies' share of the future obligation to decommission these units is approximately $1.9 billion in current dollars and (using a 4.0% escalation rate) approximately $4.5 billion in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Payments for decommissioning are expected to begin in 2016, when actual decommissioning work begins. The Companies have recovered approximately $342 million for decommissioning through their electric rates from customers through December 31, 2000. The Companies have also recognized an estimated liability of approximately $31.6 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992. The Financial Accounting Standards Board (FASB) issued a proposed accounting standard for nuclear decommissioning costs in 1996. If the standard is adopted as proposed: (1) annual provisions for decommissioning could change; (2) the net present value of estimated decommissioning costs could be recorded as a liability; and (3) income from the external decommissioning trusts could be reported as investment income. The FASB subsequently expanded the scope of the proposed standard to include other closure and removal obligations related to long-lived assets. A final pronouncement is expected in the second quarter of 2001 and is anticipated to be implemented on January 1, 2002. NUCLEAR FUEL- OE's and Penn's nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. CEI and TE severally lease their respective portions of nuclear fuel and pay for the fuel as it is consumed (see Note 3). The Companies amortize the cost of nuclear fuel based on the rate of consumption. INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Alternative minimum tax credits of $32 million, which may be carried forward indefinitely, are available to reduce future federal income taxes. RETIREMENT BENEFITS- The Companies' trusteed, noncontributory defined benefit pension plan covers almost all full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. The Companies use the projected unit credit method for funding purposes and were not required to make pension contributions during the three years ended December 31, 2000. The assets of the pension plan consist primarily of common stocks, United States government bonds and corporate bonds. The Companies provide a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Companies pay insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Companies. The Companies recognize the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. The following sets forth the funded status of the plans and amounts recognized on the Consolidated Balance Sheets as of December 31:
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) ===================================================================================== 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%
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 ==================================================================================================
The 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. 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 fair market value. Noncash financing and investing activities included capital lease transactions amounting to $89.3 million, $36.2 million and $61.8 million for the years 2000, 1999 and 1998, respectively. Commercial paper transactions of OES Fuel, Incorporated (OES Fuel) (a wholly owned subsidiary of OE) 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 4G). 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 $5,853 $6,010 $6,381 $6,331 Preferred stock $ 247 $ 243 $ 295 $ 280 Investments other than cash and cash equivalents: Debt securities ?Maturity (5-10 years) $ 460 $ 441 $ 475 $ 476 ?Maturity (more than 10 years) 1,026 1,051 1,068 1,013 Equity securities 16 16 17 17 All other 924 935 852 874 ----------------------------------------------------------------------- $2,426 $2,443 $2,412 $2,380 =====================================================================
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 a corresponding change to the decommissioning liability. The Companies have no securities held for trading purposes. Effective December 31, 1998, the Company began accounting for its commodity price derivatives, entered into specifically for trading purposes, on a mark-to-market basis in accordance with Emerging Issues Task Force Issue 98-10, "Accounting for Energy Trading and Risk Management Activities," with gains and losses recognized currently in the Consolidated Statements of Income. The contracts that were marked to market are included in the Consolidated Balance Sheets as Deferred Charges and Deferred Credits at their fair values. The impact on the consolidated financial statements was immaterial. On January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an amendment of FASB Statement No. 133." The cumulative effect of adopting SFAS 133, as amended, increases assets by $108.3 million, liabilities by $72.6 million and common stockholders' equity by $35.7 million -- other comprehensive income increases by $44.2 million and net income is reduced by $8.5 million. 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. OE and Penn 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 OE's generation business and the nonnuclear generation businesses of CEI and TE was discontinued effective with the PUCO's approval of the Company'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 $1.6 billion ($1.2 billion, $304 million and $53 million for OE, CEI and TE, respectively). Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:
2000 1999 ------------------------------------------------------------------ (In millions) Nuclear unit expenses $1,081.1 $1,123.0 Customer receivables for future income taxes 173.5 444.3 Rate stabilization program deferrals 400.0 420.1 Sale and leaseback costs 8.0 17.8 Competitive transition charge 230.9 280.4 Loss on reacquired debt 167.1 173.9 Employee postretirement benefit costs 20.7 24.8 DOE decommissioning and decontamination costs 26.8 29.5 Impaired generating assets 1,595.5 -- Other 24.1 29.6 ------------------------------------------------------------------ Total $3,727.7 $2,543.4 ================================================================
2. MERGER AGREEMENT: On August 8, 2000, FirstEnergy and GPU, Inc. (GPU), a Pennsylvania corporation, entered into an Agreement and Plan of Merger. Under the merger agreement, FirstEnergy would acquire all of the outstanding shares of GPU's common stock for approximately $4.5 billion in cash and FirstEnergy common stock. Approximately $7.4 billion of debt and preferred stock of GPU's subsidiaries would remain outstanding. The transaction would be accounted for by the purchase method. The combined company's principal electric utility operating companies would include OE, CEI, TE, Penn and ATSI, as well as GPU's electric utility operating companies - Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company, which serve customers in New Jersey and Pennsylvania. Under the agreement, GPU shareholders would receive the equivalent of $36.50 for each share of GPU common stock they own, payable in cash or in FirstEnergy common stock, as long as FirstEnergy's common stock price is between $24.2438 and $29.6313. Each GPU shareholder would be able to elect the form of consideration they wish to receive, subject to proration so that the aggregate consideration to all GPU shareholders will be 50 percent cash and 50 percent FirstEnergy common stock. Each GPU share converted into FirstEnergy common stock would receive not less than 1.2318 and not more than 1.5055 shares of FirstEnergy common stock, depending on the average closing price of FirstEnergy stock during the 20-day trading period ending on the seventh trading date prior to the merger closing. The stock portion of the consideration is expected to be tax-free to GPU shareholders. The merger has been approved by the respective shareholders of the Company and GPU and is expected to close promptly after all of the conditions to the consummation of the merger, including the receipt of all necessary regulatory approvals, are fulfilled or waived. The receipt of all necessary regulatory approvals, including, but not limited to, the FERC, the Nuclear Regulatory Commission, the Federal Communications Commission, and the SEC, are expected by the end of the second quarter of 2001. 3. LEASES: The Companies lease certain generating facilities, nuclear fuel, office space and other property and equipment under cancelable and noncancelable leases. OE sold portions of its ownership interests 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. CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE continue to be responsible, to the extent of their 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. They have the right, at the end of the respective basic lease terms, to renew their respective leases. They 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. The basic rental payments are adjusted when applicable federal tax law changes. OES Finance, Incorporated (OES Finance), a wholly owned subsidiary of OE, maintains deposits pledged as collateral to secure reimbursement obligations relating to certain letters of credit supporting OE'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 OE as sole owner of OES Finance common stock. Nuclear fuel is currently financed for CEI and TE through leases with a special-purpose corporation. As of December 31, 2000, $142 million of nuclear fuel was financed under a lease financing arrangement through $150 million of 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, are summarized as follows:
2000 1999 1998 --------------------------------------------------------- (In millions) Operating leases Interest element $202.4 $208.6 $201.2 Other 111.1 110.3 147.8 Capital leases Interest element 12.3 17.5 17.6 Other 64.2 76.1 66.3 --------------------------------------------------------- Total rentals $390.0 $412.5 $432.9 =======================================================
The future minimum lease payments as of December 31, 2000, are:
Operating Leases ---------------------------------- Capital Lease Capital Leases Payments Trusts Net ------------------------------------------------------------------------- (In millions) 2001 $ 74.3 $ 306.8 $ 146.0 $ 160.8 2002 50.1 317.9 169.5 148.4 2003 32.9 326.1 176.5 149.6 2004 19.6 291.3 110.7 180.6 2005 9.6 310.1 128.8 181.3 Years thereafter 17.7 3,321.2 1,235.6 2,085.6 ------------------------------------------------------------------------- Total minimum lease payments 204.2 $4,873.4 $1,967.1 $2,906.3 Executory costs 10.6 ======== ======== ======== ------------------------------------ Net minimum lease payments 193.6 Interest portion 30.4 ------------------------------------ Present value of net minimum lease payments 163.2 Less current portion 52.0 ------------------------------------ Noncurrent portion $111.2 ===================================
OE invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. CEI and TE established the Shippingport Capital Trust to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport capital trust arrangements effectively reduce lease costs related to those transactions. 4. CAPITALIZATION: (A) RETAINED EARNINGS- There are no restrictions on retained earnings for payment of cash dividends on the Company's common stock. (B) EMPLOYEE STOCK OWNERSHIP PLAN- The Companies fund the matching contribution for their 401(k) savings plan through an ESOP Trust. All full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. 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. In 2000, 1999 and 1998, 826,873 shares, 627,427 shares and 423,206 shares, respectively, were allocated to employees with the corresponding expense recognized based on the shares allocated method. The fair value of 5,952,032 shares unallocated as of December 31, 2000, was approximately $187.8 million. Total ESOP-related compensation expense was calculated as follows:
2000 1999 1998 ----------------------------------------------------------------------- (In millions) Base compensation $18.7 $18.3 $13.5 Dividends on common stock held by the ESOP and used to service debt (6.4) (4.5) (3.9) ------------------------------------------------------------------------ Net expense $12.3 $13.8 $ 9.6 ========================================================================
(C) STOCK COMPENSATION PLANS- On April 30, 1998, the Company adopted the Executive and Director Incentive Compensation Plan (FE Plan). The FE Plan permits awards to be made to key employees in the form of restricted stock, stock options, stock appreciation rights, performance shares or cash. Common stock granted under the FE Plan may not exceed 7.5 million shares. No stock appreciation rights or performance shares have been issued under the FE Plan. Restricted common stock shares were granted under the FE Plan in 1998, 1999 and 2000 for various vesting periods ranging from six months to eight years. The restricted common stock shares were purchased in the open market and have full voting and dividend rights. There were no exercise prices related to these shares. Restricted common stock grants were as follows:
2000 1999 1998 ---------------------------------------------------------------- Restricted common shares granted 208,400 8,000 20,000 Weighted average market price $26.63 $30.89 $30.78 Weighted average vesting period 3.8 5.8 4.0 Dividends restricted Yes Yes No ----------------------------------------------------------------
FE Plan options were granted in 1998, 1999 and 2000 and are exercisable after four years from the date of grant with some acceleration of vesting possible based on performance. Stock options, which were granted prior to 1998, expire on or before February 25, 2007. Stock option activity was as follows:
Number of Weighted Average Stock Option Activity Options Exercise Price ------------------------------------------------------------------------- Balance at December 31, 1997 517,388 $24.59 (517,388 options exercisable) Options granted 189,491 29.82 Options exercised 335,058 24.67 Options forfeited 7,535 29.82 Balance at December 31, 1998 364,286 27.13 (182,330 options exercisable) Options granted 1,811,658 24.90 Options exercised 22,575 21.42 Balance at December 31, 1999 2,153,369 25.32 (159,755 options exercisable) Options granted 3,011,584 23.24 Options exercised 90,491 26.00 Options forfeited 52,600 22.20 Balance at December 31, 2000 5,021,862 24.09 (473,314 options exercisable) -------------------------------------------------------------------------
As of December 31, 2000, the weighted average remaining contractual life of outstanding stock options was 8.4 years. Under the Executive Deferred Compensation Plan, adopted January 1, 1999, employees can direct a portion of their Annual Incentive Award and/or Long Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout occurs three years from the date of deferral. As of December 31, 2000, there were 123,787.48 stock units outstanding. The Company continues to apply Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees." As required by SFAS 123, "Accounting for Stock-Based Compensation," the Company has determined pro forma earnings as though the Company had accounted for employee stock options under the fair value method. The weighted average assumptions used in valuing the options and their resulting fair values are as follows:
2000 1999 1998 --------------------------------------------------------------- Valuation assumptions: Expected option term (years) 7.6 6.4 10 Expected volatility 21.77% 20.03% 15.50% Expected dividend yield 6.68% 5.97% 5.68% Risk-free interest rate 5.28% 5.97% 5.65% Fair value per option $2.86 $3.42 $3.25 ---------------------------------------------------------------
The following table summarizes the pro forma effect of applying fair value accounting to the Company's stock options.
2000 1999 1998 ------------------------------------------------------------------ Net Income (000) As Reported $598,970 $568,299 $410,874 Pro Forma $597,378 $567,876 $410,839 Earnings Per Share of Common Stock - Basic and Diluted As Reported $2.69 $2.50 $1.82 Pro Forma $2.69 $2.50 $1.81 -------------------------------------------------------------------
(D) PREFERRED AND PREFERENCE STOCK- Penn's 7.75% series of preferred stock has a restriction which prevents early redemption prior to July 2003. OE's 8.45% series of preferred stock has no optional redemption provision. CEI'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 Companies in whole, or in part, with 30-90 days' notice. Preference stock authorized for the Companies are 8 million shares without par value for OE; 3 million shares without par value for CEI; and 5 million shares, $25 par value for TE. No preference shares are currently outstanding. (E) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- Annual sinking fund provisions for the Companies' preferred stock are as follows:
Redemption Price Per Series Shares Share Date Beginning -------------------------------------------------------------------------- OE 8.45% 50,000 $ 100 (i) CEI $ 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 Penn 7.625% 7,500 100 October 1 2002 -------------------------------------------------------------------------- (i) Sinking fund provisions are in effect.
Annual sinking fund requirements for the next five years are $85 million in 2001, $19 million in 2002 and $2 million in each year 2003-2005. (F) OHIO EDISON OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY OHIO EDISON SUBORDINATED DEBENTURES- Ohio Edison Financing Trust, a wholly owned subsidiary of OE, has issued $120 million of 9% Cumulative Trust Preferred Capital Securities. OE 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 OE 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. OE'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 OE of payments due on the Preferred Securities. (G) 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, OE's, TE's and Penn's annual sinking and improvement fund requirements for all bonds issued under the mortgage amounts to $31.4 million. OE, TE and Penn 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 $399.0 2002 945.0 2003 460.1 2004 833.9 2005 436.3 --------------------------
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 $341.2 million and noncancelable municipal bond insurance policies of $280 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 1.375% of the amounts of the letters of credit to the issuing banks and are obligated to reimburse the banks for any drawings thereunder. OE 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. OE must pay an annual facility fee of 0.20% on the total credit facility amount. In addition, the credit agreement provides that OE maintain unused first mortgage bond capability for the full credit agreement amount under OE's indenture as potential security for the unsecured borrowings. CEI 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 CEI and TE in the proportion of 40% and 60%, respectively (see Note 3). OE's and Penn's 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. (H) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity except those resulting from transactions with common stockholders. As of December 31, 2000, accumulated other comprehensive income (loss) consisted of a minimum liability for unfunded retirement benefits of $(329,000) and an unrealized gain on investment of securities available for sale of $922,000. 5. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT: Short-term borrowings outstanding as of December 31, 2000, consisted of $539.8 million of bank borrowings and $159.9 million of OES Capital, Incorporated (OES Capital) commercial paper. OES Capital is a wholly owned subsidiary of OE 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. The Companies have various credit facilities with domestic banks that provide for borrowings of up to $505 million under various interest rate options. OE's short-term borrowings may be made under its lines of credit on its unsecured notes. To assure the availability of these lines, the Companies are required to pay annual commitment fees that vary from 0.15% to 0.375%. 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 7.92% and 6.51%, respectively. 6. COMMITMENTS AND CONTINGENCIES: CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $3.0 billion for property additions and improvements from 2001-2005, of which approximately $683 million is applicable to 2001. Investments for additional nuclear fuel during the 2001-2005 period are estimated to be approximately $380 million, of which approximately $54 million applies to 2001. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $460 million and $100 million, respectively, as the nuclear fuel is consumed. STOCK REPURCHASE PROGRAM- On November 17, 1998, the Board of Directors authorized the repurchase of up to 15 million shares of the Company's common stock over a three-year period beginning in 1999. Repurchases are made on the open market, at prevailing prices, and are funded primarily through the use of operating cash flows. During 2000 and 1999, the Company repurchased and retired 7.9 million shares (average price of $24.51 per share) and 4.6 million shares (average price of $28.08 per share), respectively. 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. The Companies' maximum potential assessment under the industry retrospective rating plan would be $352.4 million per incident but not more than $40 million in any one year for each incident. The Companies are also insured under policies for each nuclear 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 $789 million of insurance coverage for replacement power costs. Under these policies, the Companies can be assessed a maximum of approximately $38 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. The Companies estimate additional capital expenditures for environmental compliance of approximately $201 million, which is included in the construction forecast provided under "Capital Expenditures" for 2001 through 2005. 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. The Companies continue to evaluate their 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 OE and Penn 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 Company believes 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. CEI and TE have been named as "potentially responsible parties" (PRPs) 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. CEI and TE have accrued liabilities totaling $3.7 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. CEI and TE believe that waste disposal costs will not have a material adverse effect on their financial condition, cash flows or results of operations. 7. SEGMENT INFORMATION: The Company operates under the following reportable segments: regulated services, competitive services and other (primarily corporate support services). The Company's primary segment is its regulated services, which include five electric utility operating companies that formerly provided bundled electric service in Ohio and Pennsylvania. Its other material business segment consisted of the subsidiaries that operate unregulated businesses. During 2000, the Company made certain organizational changes to further align its business units to accommodate its retail strategy and the impact of its plan to move the generation portion of its electricity services from the regulated segment to the competitive segment as reflected in its approved Ohio transition plan. These reportable segments are strategic businesses, which are managed and operated differently based on the degree of regulation, and the products and services offered. The regulated services segment designs, constructs, operates and maintains our regulated transmission and distribution systems. It also provides generation services to regulated franchise customers who have not chosen an alternative, competitive generation supplier. The regulated services segment obtains generation through power supply agreements with the competitive services segment. The competitive services segment includes all unregulated energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation, trading and sourcing of commodity requirements, as well as other competitive energy-application services. Competitive products are increasingly marketed to customers as bundled services. Segment Financial Information -----------------------------
Regulated Competitive Reconciling Services Services Other Adjustments Consolidated --------- ----------- ----- ----------- ------------ (In millions) 2000 ---- External revenues $ 4,747 $2,020 $ 8 $ 254 (A) $ 7,029 Intersegment revenues 28 1,827 303 (2,158)(B) -- Total revenues 4,775 3,847 311 (1,904) 7,029 Depreciation and amortization 790 194 13 (63)(C) 934 Income taxes 561 68 1 (253)(D) 377 Net operating profit after taxes 916 128 3 (448)(E) 599 Total assets 15,688 1,933 320 -- 17,941 1999 ---- External revenues $ 4,723 $1,218 $ 16 $ 363 (A) $ 6,320 Intersegment revenues 55 1,301 181 (1,537)(B) -- Total revenues 4,778 2,519 197 (1,174) 6,320 Depreciation and amortization 789 170 9 (30)(C) 938 Income taxes 574 75 (32) (222)(D) 395 Net operating profit after taxes 977 126 (61) (474)(E) 568 Total assets 15,931 1,514 779 -- 18,224 1998 ---- External revenues $ 4,802 $ 934 $ 8 $ 131 (A) $ 5,875 Intersegment revenues -- 2,806 144 (2,950)(B) -- Total revenues 4,802 3,740 152 (2,819) 5,875 Depreciation and amortization 784 8 5 (38)(C) 759 Income taxes 822 (40) (22) (456)(D) 304 Net operating profit after taxes 893 (59) (43) (350)(E) 441 Total assets 15,918 1,558 716 -- 18,192 Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting: (A) Principally interest income and revenues related to gross receipts taxes which are excluded for internal management reporting purposes. (B) Elimination of intersegment revenues. (C) Reclassification for amortization of tax regulatory assets included in income taxes for external financial reporting; reduction for depreciation expense recognized for internal management reporting for assets subject to sale and leaseback transactions (see Note 3); and recognition of goodwill amortization which is excluded for internal management reporting. (D) Income tax effects of the differences described above and the tax benefit of interest expense not otherwise included in the computation of net operating profit after taxes. (E) The net effect from the differences described above and the recognition of interest costs not included in net operating profit after taxes for internal management reporting purposes.
Products and Services ---------------------
Oil & Gas Energy Related Electricity Sales and Sales and Year Sales Production Services ---- ----------- ---------- -------------- (In millions) 2000 $5,537 $582 $563 1999 5,253 203 503 1998 4,980 26 198
8. 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, except per share amounts) Revenues $1,607.9 $1,702.1 $1,891.7 $1,827.3 Expenses 1,234.1 1,338.0 1,433.1 1,518.9 ----------------------------------------------------------------------------------------------- Income Before Interest and Income Taxes 373.8 364.1 458.6 308.4 Net Interest Charges 135.0 134.4 131.2 128.5 Income Taxes 97.9 95.1 129.2 54.6 ----------------------------------------------------------------------------------------------- Net Income $ 140.9 $ 134.6 $ 198.2 $ 125.3 ================================================================================================ Earnings per Share of Common Stock $ .63 $ .60 $ .89 $ .57 ================================================================================================
March 31, June 30, September 30, December 31, Three Months Ended 1999 1999 1999 1999 ----------------------------------------------------------------------------------------------- (In millions, except per share amounts) Revenues $1,417.4 $1,523.9 $1,732.4 $1,645.9 Expenses 1,041.7 1,149.8 1,291.0 1,301.7 ----------------------------------------------------------------------------------------------- Income Before Interest and Income Taxes 375.7 374.1 441.4 344.2 Net Interest Charges 146.1 147.4 141.3 137.5 Income Taxes 92.9 101.4 114.3 86.2 ----------------------------------------------------------------------------------------------- Net Income $ 136.7 $ 125.3 $ 185.8 $ 120.5 ================================================================================================ Earnings per Share of Common Stock $ .60 $ .55 $ .82 $ .53 ================================================================================================