EX-13 24 cei_ex13-2.txt EX 13-2 CEI ANNUAL REPORT THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 2003 ANNUAL REPORT TO STOCKHOLDERS The Cleveland Electric Illuminating Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the generation, distribution and sale of electric energy in an area of approximately 1,700 square miles in northeastern Ohio. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 1.9 million. Contents Page -------- ---- Selected Financial Data...................................... 1 Management's Discussion and Analysis......................... 2-13 Consolidated Statements of Income............................ 14 Consolidated Balance Sheets.................................. 15 Consolidated Statements of Capitalization.................... 16-17 Consolidated Statements of Common Stockholder's Equity....... 18 Consolidated Statements of Preferred Stock................... 18 Consolidated Statements of Cash Flows........................ 19 Consolidated Statements of Taxes............................. 20 Notes to Consolidated Financial Statements................... 21-39 Report of Independent Auditors............................... 40
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY SELECTED FINANCIAL DATA 2003 2002 2001 2000 1999 --------------------------------------------------------------------------------------------------------------------- (Dollars in thousands) GENERAL FINANCIAL INFORMATION: Operating Revenues...................... $1,720,784 $1,843,671 $2,064,622 $1,890,339 $1,864,954 ========== ========== ========== ========== ========== Operating Income........................ $ 255,148 $ 306,152 $ 354,422 $ 397,568 $ 405,640 ========== ========== ========== ========== ========== Income Before Cumulative Effect of Accounting Change................. $ 197,033 $ 136,952 $ 177,905 $ 210,424 $ 204,963 ========== ========== ========== ========== ========== Net Income.............................. $ 239,411 $ 136,952 $ 177,905 $ 210,424 $ 204,963 ========== ========== ========== ========== ========== Earnings on Common Stock................ $ 231,885 $ 121,262 $ 153,067 $ 189,581 $ 171,439 ========== ========== ========== ========== ========== Total Assets............................ $6,773,448 $6,510,243 $6,526,596 $6,756,921 $6,189,261 ========== ========== ========== ========== ========== CAPITALIZATION AS OF DECEMBER 31: Common Stockholder's Equity............. $1,778,827 $1,200,001 $1,082,041 $1,095,874 $ 990,177 Preferred Stock- Not Subject to Mandatory Redemption.. 96,404 96,404 141,475 238,325 238,325 Subject to Mandatory Redemption...... -- 105,021 106,288 26,105 116,246 Long-Term Debt.......................... 1,884,643 1,975,001 2,156,322 2,634,692 2,682,795 ---------- ---------- ---------- ---------- ---------- Total Capitalization.................... $3,759,874 $3,376,427 $3,486,126 $3,994,996 $4,027,543 ========== ========== ========== ========== ========== CAPITALIZATION RATIOS: Common Stockholder's Equity............. 47.3% 35.5% 31.0% 27.4% 24.6% Preferred Stock- Not Subject to Mandatory Redemption.. 2.6 2.9 4.1 6.0 5.9 Subject to Mandatory Redemption...... -- 3.1 3.0 0.6 2.9 Long-Term Debt.......................... 50.1 58.5 61.9 66.0 66.6 ----- ----- ----- ----- ----- Total Capitalization.................... 100.0% 100.0% 100.0% 100.0% 100.0% ===== ===== ===== ===== ===== DISTRIBUTION KILOWATT-HOUR DELIVERIES (Millions): Residential............................. 5,216 5,370 5,061 5,061 5,278 Commercial.............................. 4,690 4,628 4,907 6,656 6,509 Industrial.............................. 8,908 8,921 9,593 8,320 8,069 Other................................... 169 167 166 167 166 ------ ------ ------ ------ ------ Total................................... 18,983 19,086 19,727 20,204 20,022 ====== ====== ====== ====== ====== CUSTOMERS SERVED: Residential............................. 669,337 677,095 673,852 667,115 667,954 Commercial.............................. 80,596 71,893 70,636 69,103 69,954 Industrial.............................. 2,318 4,725 4,783 4,851 5,090 Other................................... 286 289 292 307 223 ------- ------- ------- ------- ------- Total................................... 752,537 754,002 749,563 741,376 743,221 ======= ======= ======= ======= ======= Number of Employees..................... 949 974 1,025 1,046 1,694
1 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These 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, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), adverse regulatory or legal decisions and the outcome of governmental investigations, availability and cost of capital, the continuing availability and o peration of generating units, the inability of the Davis-Besse Nuclear Power Station to restart (including because of an inability to obtain a favorable final determination from the Nuclear Regulatory Commission) in Spring 2004, inability to accomplish or realize anticipated benefits from strategic goals, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities market, further investigation into the causes of the August 14, 2003, regional power outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outage, a denial of or material change to the Company's Application related to its Rate Stabilization Plan, and other similar factors. Restatements ------------ We restated our consolidated financial statements for the three years ended December 31, 2002 to reflect a change in the method of amortizing costs being recovered under the Ohio transition plan and to recognize above-market liabilities of certain leased generation facilities. Financial comparisons described below reflect the effect of these restatements and reclassifications on 2002 financial results. Results of Operations --------------------- Earnings on common stock in 2003 increased 91.2% to $231.9 million from $121.3 million in 2002. The increase in earnings in 2003 was due primarily to a gain of $74.7 million, net of tax, representing net proceeds from the settlement of our claim against NRG Energy, Inc. relating to the terminated sale of three of our fossil power plants (see Note 6). Also contributing to the increase in earnings was a $42.4 million gain from the cumulative effect of adopting Statement of Financial Accounting Standards (SFAS) 143, "Accounting for Asset Retirement Obligations." Excluding these gains, earnings on common stock decreased $6.4 million or 5%, in 2003. The decrease resulted primarily from lower operating revenues, which were partially offset by lower operating expenses, net interest charges and preferred stock dividend requirements. Earnings on common stock in 2002 decreased 20.8% to $121.3 million in 2002 from $153.1 million in 2001. The earnings decrease in 2002 primarily resulted from lower operating revenues, which was partially offset by lower operating expenses, net interest charges and preferred stock dividend requirements. Operating revenues decreased $122.9 million or 6.7% in 2003 compared with 2002. The lower revenues were due to milder weather and increased sales by alternative suppliers. Kilowatt-hour sales to retail customers declined by 13.6% in 2003 from the prior year, with declines in all customer sectors (residential, commercial and industrial), resulting in a $56.0 million reduction in generation sales revenue. Kilowatt-hour sales of electricity by alternative suppliers in our franchise area increased by 9 percentage points in 2003 from last year. Further decreasing operating revenues were Ohio transition plan incentives, provided to customers to encourage switching to alternative energy providers - $30.1 million of additional credits were provided to customers in 2003 compared with 2002. These revenue reductions are deferred for future recovery under our transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers (primarily FirstEnergy Solutions (FES), an affiliated company) decreased by $25.8 million in 2003 compared with 2002. The lower sales resulted from reductions in available nuclear generation of 17.2% in 2003 compared to 2002. Available generation decreased due to the extended outage of Davis-Besse and generating capacity removed from service due to additional nuclear refueling activities in 2003 compared to 2002. Operating revenues decreased $221.0 million or 10.7% in 2002 compared with 2001. The lower revenues reflected the effects of a sluggish national economy on our service area, shopping by Ohio customers for alternative energy providers and decreases in wholesale revenues. Retail kilowatt-hour sales declined by 23.9% in 2002 from the prior year, with declines in all customer sectors (residential, commercial and industrial), resulting in a $123.0 million reduction in generation sales revenue. Our lower generation kilowatt-hour sales resulted primarily from customer choice in Ohio. Sales of electric generation by alternative suppliers as a percent of total sales delivered in our franchise area 2 increased to 31.5% in 2002 from 12.9% in 2001, while our share of electric generation sales in our franchise areas decreased by 18.6% compared to the prior year. Distribution deliveries decreased 3.3% in 2002 compared with 2001, which decreased revenues from electricity throughput by $18.9 million in 2002 from the prior year. The lower distribution deliveries resulted from the effect that continued sluggishness in the economy had on demand by commercial and industrial customers which was offset in part by the additional residential demand due to warmer summer weather. Customer shopping incentives further reduced operating revenues $43.4 million in 2002 from the prior year. Sales revenues from wholesale customers decreased by $43.8 million in 2002 compared to 2001, due to lower kilowatt-hour sales. The reduced kilowatt-hour sales resulted from lower sales to FES, reflecting the extended outage at Davis-Besse. Changes in electric generation sales and distribution deliveries in 2003 and 2002, compared to the prior year, are summarized in the following table: Changes in KWH Sales 2003 2002 --------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (13.6)% (23.9)% Wholesale............................. (12.4)% (12.8)% ---------------------------------------------------------------------- Total Electric Generation Sales......... (13.0)% (18.9)% ===================================================================== Distribution Deliveries: Residential........................... (2.9)% 6.1% Commercial and industrial............. 0.4% (6.6)% ---------------------------------------------------------------------- Total Distribution Deliveries........... (0.5)% (3.3)% ===================================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $71.9 million in 2003 and by $172.7 million in 2002 from 2001. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes 2003 2002 --------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel and purchased power..................... $ 8.2 $(181.2) Nuclear operating costs...................... 33.7 98.7 Other operating costs........................ (42.9) 16.5 -------------------------------------------------------------------- Total operation and maintenance expenses... (1.0) (66.0) Provision for depreciation and amortization.. (46.4) (59.7) General taxes................................ (11.4) 2.9 Income taxes................................. (13.1) (49.9) --------------------------------------------------------------------- Total operating expenses and taxes......... $(71.9) $(172.7) ----------------------------------------------------------------------- Higher fuel and purchased power costs in 2003 resulted from an increase in purchased power costs partially offset by lower fuel costs from reduced nuclear generation. Higher purchased power costs primarily reflect increased unit costs partially offset by lower power purchases from FES in 2003 compared to 2002. Increased nuclear costs resulted from unplanned work performed during the Perry Plant's 56-day nuclear refueling outage (44.85% ownership) in the Spring of 2003, and the Beaver Valley Unit 2 28-day refueling outage (24.47% ownership) in the third quarter of 2003, compared with the 24-day refueling outage at Beaver Valley Unit 2 in the first quarter of 2002. Lower other operating costs in 2003 reflect lower employee costs -- specifically the absence of short-term incentive compensation and reduced health care costs. Lower fuel and purchased power costs in 2002 resulted from a $177.0 million reduction in power purchased from FES, reflecting lower kilowatt-hours purchased due to reduced kilowatt-hour sales and lower unit prices. Nuclear operating costs increased $98.7 million in 2002, primarily due to approximately $59.1 million of incremental Davis-Besse maintenance costs related to its extended outage (see Davis-Besse Restoration). The $16.5 million increase in other operating costs resulted principally from higher employee benefit costs. The decrease in depreciation and amortization charges in 2003 was primarily attributable to several factors - higher shopping incentive deferrals ($30.1 million), lower charges following the implementation of SFAS 143 ($17.5 million) and lower fossil plant depreciation ($13.6 million) - partially offset by higher transition plan amortization ($17.7 million). Charges for depreciation and amortization decreased by $59.7 million in 2002 from 2001 primarily due to higher shopping incentive deferrals and tax-related deferrals under our transition plan, and the cessation of goodwill amortization. 3 General taxes decreased $11.4 million in 2003 from 2002 principally due to settled property tax claims. Net Interest Charges Net interest charges continued to trend lower, decreasing by $29.3 million in 2003 and by $4.6 million in 2002 due to our debt paydown program. Our redemption and refinancing activities during 2003 totaled $416 million and $194 million, respectively, and are expected to result in annualized savings of approximately $39 million. Cumulative Effect of Accounting Changes Results for 2003 include an after-tax credit to net income of $42.4 million recorded upon adoption of SFAS 143 in January 2003. We identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143, asset retirement costs of $49.9 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $6.8 million. The asset retirement obligation (ARO) liability at the date of adoption was $238.3 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, we had recorded decommissioning liabilities of $242.5 million. The cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $72.5 million increase to income, or $42.4 million net of income taxes. Preferred Stock Dividend Requirements Preferred stock dividend requirements were $8.2 million lower in 2003, compared to the prior year principally due to optional redemptions of preferred stock in 2002. The redemption resulted in a decrease of $9.1 million in 2002. Premiums related to the optional redemptions partially offset the lower dividend requirements. Capital Resources and Liquidity ------------------------------- Through net debt and preferred stock redemptions, we continued to reduce the cost of debt and preferred stock, and improve our financial position in 2003. During 2003, we reduced our total outstanding debt by approximately $490 million, partially funded by a $300 million equity contribution from FirstEnergy. As a result, our common stockholder's equity as a percentage of total capitalization increased to 47% as of December 31, 2003 from 21% at the end of 1997. Over the last six years, we have reduced the average cost of outstanding debt from 8.15% in 1997 to 6.56% in 2003. Changes in Cash Position As of December 31, 2003, we had $24.8 million of cash and cash equivalents, compared with $30.4 million as of December 31, 2002. Cash and cash equivalents included $25 million received in December 2003 which was included in the NRG settlement claim sold in January 2004 (see Note 6) and $30 million used for the redemption of long-term debt in January 2003 as of December 31, 2003 and 2002, respectively. The major sources for changes in these balances are summarized below. Cash Flows from Operating Activities Our consolidated net cash from operating activities is provided by our regulated energy services. Net cash provided from operating activities was $364.8 million in 2003, $317.2 million in 2002 and $365.5 million in 2001. Cash flows provided from operating activities are as follows: Operating Cash Flows 2003 2002 2001 ------------------------------------------------------------------------ (In millions) Cash earnings (1)............. $309.4 $326.5 $ 467.6 Working capital and other..... 55.4 (9.3) (102.1) ------------------------------------------------------------------------ Total................... $364.8 $317.2 $365.5 ======================================================================== (1) Includes net income, depreciation and amortization, deferred operating lease costs, deferred income taxes, investment tax credits and major noncash charges. Net cash from operating activities increased $48 million in 2003 compared to 2002 as a result of a $65 million reduction in working capital and other requirements partially offset by a $17 million reduction in cash earnings. The largest factor contributing to the working capital and other decrease was an $80 million increase in accrued taxes. 4 Cash Flows from Financing Activities In 2003, the net cash used for financing activities of $197.9 million primarily reflects the redemptions of debt and preferred stock shown below. The following table provides details regarding new issues and redemptions during 2003 and 2002: Securities Issued or Redeemed 2003 2002 --------------------------------------------------------------------------- (In millions) New Issues ---------- Pollution Control Notes................... -- $107.0 Unsecured Notes........................... $296.9 -- ---------------------------------------------------------------------------- Short-term Borrowings, Net..................... $ -- $190.9 ============================================================================ Redemptions ----------- First Mortgage Bonds...................... 550.0 195.0 Pollution Control Notes................... 111.7 78.7 Secured Notes............................. 15.0 33.0 Preferred Stock........................... 1.1 164.7 Other..................................... 0.4 2.8 --------------------------------------------------------------------------- 678.2 474.2 Short-term Borrowings, Net..................... $109.2 $ -- =========================================================================== We had about $25.3 million of cash and temporary investments and approximately $188.2 million of short-term indebtedness at the end of 2003. We had the capability to issue approximately $1.1 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds, although unsecured senior note indentures entered into by the Company in 2003 limit our ability to issue secured debt, including FMBs, subject to certain exceptions. We have no restrictions on the issuance of preferred stock. At the end of 2003, our common equity as a percentage of capitalization, including debt relating to assets held for sale, stood at 47% compared to 36% at the end of 2002. We have the ability to borrow from our regulated affiliates and FirstEnergy to meet our short-term working capital requirements. FirstEnergy Service Company administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2003 was 1.47%. Our access to capital markets and costs of financing are dependent on the ratings of our securities and that of our holding company, FirstEnergy. The following table shows our securities' ratings following the downgrade by Moody's Investors Service in February 2004. The ratings outlook on all securities is stable. Ratings of Securities ------------------------------------------------------------------------------ Securities S&P Moody's Fitch ------------------------------------------------------------------------------ FirstEnergy Senior unsecured BB+ Baa3 BBB- CEI Senior secured BBB- Baa2 BBB- Senior unsecured BB+ Baa3 BB Preferred stock BB Ba2 BB- ---------------------------------------------------------------------------- On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior secured, senior unsecured, and preferred stock ratings of CEI. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the securities of its electric utility operating companies. Fitch stated that the changes to the long-term ratings were "driven by the high debt leverage of the parent, FirstEnergy. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been vulnerable to unfavorable events, slowing the pace of FirstEnergy's debt reduction efforts. The Stable Outlook reflects the success of FirstEnergy's recent common equity offering and management's focus on a relatively conservative integrated utility strategy." On December 23, 2003, Standard & Poor's (S&P) lowered its corporate credit ratings on FirstEnergy and its regulated utility subsidiaries to "BBB-" from "BBB" and lowered FirstEnergy's senior unsecured debt rating to "BB+" from "BBB-". CEI's ratings were lowered one notch as well. The ratings were removed from CreditWatch with negative implications, where 5 they had been placed by S&P on August 18, 2003, and the Ratings Outlook returned to Stable. The rating action followed a revision in S&P's assessment of our consolidated business risk profile to `6' from `5' (`1' equals low risk, `10' equals high risk), with S&P citing operational and management challenges as well as heightened regulatory uncertainty for its revision of our business risk assessment score. S&P's rationale for its revisions of the ratings included uncertainty regarding the timing of the Ohio Rate Plan filing (see State Regulatory Matters), the pending final report on the August 14 blackout (see Power Outage), the outcome of the remedial phase of litigation relating to the Sammis plant, and the extended Davis-Besse outage and the related pending subpoena (see Davis-Besse Restoration). S&P further stated that the restart of Davis-Besse and a supportive Ohio Rate Plan extension will be vital positive developments that would aid an upgrade of FirstEnergy's ratings. S&P's reduction of the credit ratings in December 2003 triggered cash and letter-of-credit collateral calls of FirstEnergy in addition to higher interest rates for some outstanding borrowings. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2. Ratings of the Company were confirmed. Moody's said that FirstEnergy's lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." Cash Flows from Investing Activities Net cash used in investing activities totaled $172.5 million in 2003. The net cash used for investing resulted from property additions, which was offset in part by a reduction of the investment in collateralized lease bonds. Expenditures for property additions primarily include expenditures supporting our distribution of electricity and capital expenditures related to Davis-Besse (see Davis-Besse Restoration). Our cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Over the next three years, we expect to meet our contractual obligations with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets. Contractual Obligations ----------------------- Our cash contractual obligations as of December 31, 2003 that we consider firm obligations are as follows:
Contractual Obligations Total 2004 2005-2006 2007-2008 Thereafter ----------------------------------------------------------------------------------------------------------------- (In millions) Long-term debt.................. $2,234 $288 $ 22 $269 $1,655 Short-term borrowings........... 188 188 -- -- -- Preferred stock (1)............. 5 1 2 2 -- Capital leases (2).............. 9 1 2 2 4 Operating leases (2)............ 202 27 33 21 121 Purchases (3) .................. 505 66 142 113 184 -------------------------------------------------------------------------------------------------------------- Total...................... $3,143 $571 $201 $407 $1,964 ============================================================================================================== (1) Subject to mandatory redemption. (2) Operating lease payments are net of capital trust receipts of $574.6 million (see Note 2). (3) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.
Our capital spending for the period 2004-2006 is expected to be about $275 million (excluding nuclear fuel) of which approximately $92 million applies to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $61 million, of which about $29 million relates to 2004. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $60 million and $30 million, respectively, as the nuclear fuel is consumed. Off-Balance Sheet Arrangements Obligations not included on our Consolidated Balance Sheet primarily consist of a sale and leaseback arrangement involving the Bruce Mansfield Plant, which is reflected in the operating lease payments disclosed above (see Note 2 - Leases). The present value of these sale and leaseback operating lease commitments, net of trust investments, was $134 million as of December 31, 2003. We sell substantially all of our retail customer receivables, which provided $112 million of off-balance sheet financing as of December 31, 2003. 6 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 following table. The table below presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.
Comparison of Carrying Value to Fair Value ------------------------------------------------------------------------------------------------------------------- There- Fair Year of Maturity 2004 2005 2006 2007 2008 after Total Value ------------------------------------------------------------------------------------------------------------------- (Dollars in millions) Assets Investments Other Than Cash and Cash Equivalents- Fixed Income............... $ 10 $44 $45 $ 36 $ 38 $ 665 $ 838 $ 952 Average interest rate...... 7.7% 7.9% 7.8% 7.7% 7.7% 7.1% 7.3% ____________________________________________________________________________________________________________________ Liabilities -------------------------------------------------------------------------------------------------------------------- Long-term Debt and Other Long-Term Obligations: Fixed rate.................... $288 $10 $12 $129 $140 $1,437 $2,016 $2,226 Average interest rate ..... 7.7% 7.7% 7.7% 7.2% 6.9% 7.1% 7.2% Variable rate................. $ 218 $ 218 $ 218 Average interest rate...... 1.7% 1.8% Preferred Stock Subject to Mandatory Redemption....... $ 1 $ 1 $ 1 $ 1 $ 1 $ 5 $ 5 Average dividend rate...... 7.4% 7.4% 7.4% 7.4% 7.4% 7.4% Short-term Borrowings......... $188 $ 188 $ 188 Average interest rate...... 2.2% 2.2% -------------------------------------------------------------------------------------------------------------------
Equity Price Risk ----------------- Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $188 million and $120 million as of December 31, 2003 and 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $19 million reduction in fair value as of December 31, 2003 (see Note 1(K) -Cash and Financial Instruments) Outlook ------- Beginning in 2001, our customers were able to select alternative energy suppliers. We continue to deliver power to residential homes and businesses through our existing distribution systems, which remain regulated. Customer rates have been restructured into separate components to support customer choice. We have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of our customers elects to obtain power from an alternative supplier, we reduce the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. We have continuing provider of last resort (PLR) responsibility to our franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by the PUCO and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Our regulatory assets as of December 2003 and 2002 were $ 1.1 billion and $1.2 billion, respectively. All of our regulatory assets are expected to continue to be recovered under the provisions of the transition plan. As part of the Ohio transition plan we are obligated to supply electricity to customers who do not choose an alternative supplier. We are also required to provide 400 megawatts (MW) of low cost supply to unaffiliated alternative suppliers who serve customers within our service area. Our competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in our franchise area. 7 On October 21, 2003, FirstEnergy's regulated subsidiaries filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing our support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service for our Ohio customers. Beginning in 2006, customers would pay market prices for generation as determined by the auction. Under the Rate Stabilization Plan option, customers would have price and supply stability through 2008 - three years beyond the end of the market development period - as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually to ensure that customers pay the lowest available prices; extension of our support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, we are requesting: o Extension of the transition cost amortization period from 2008 to July 2009; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. A decision is expected from the PUCO in the Spring of 2004. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will address certain problems identified by the U.S.-Canada Power System Outage Task Force (in connection with the August 14, 2003 regional power outage) and addressing how FirstEnergy proposes to upgrade its control room computer hardware and software, improve its control room training procedures and improve the training of control room operators to ensure that similar problems do not occur in the future. The PUCO, in consultation with the North American Electric Reliability Council, will review the plan before determining the next steps in the proceeding. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FirstEnergy Nuclear Operating Company (FENOC) in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, we made significant management and human performance changes with the intent of re-establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and efforts continued in 2003 to focus on design enhancements to the unit's reliability and performance. We also accelerated maintenance work that had been planned for future refueling and maintenance outages. We installed a state-of-the-art leak-detection system around the reactor, as well as modified high-pressure injection pumps. Testing of the bottom of the reactor for leaks was completed in October 2003 and no indication of leakage was discovered. The focus of activities now involves management and human performance issues. As a result, incremental maintenance and capital expenditures declined in 2003 as emphasis shifted to performance issues; replacement power costs were higher in 2003. We anticipate that Davis-Besse will be ready for restart in the first quarter of 2004. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. Delays in Davis-Besse's return to 8 service contributed to S&P's reduction in our credit rating in the fourth quarter of 2003 (see Cash Flows from Financing Activities). Incremental costs associated with the extended Davis-Besse outage (CEI's share - 51.38%) for 2003 and 2002 were as follows: Costs of Davis-Besse Increase Extended Outage 2003 2002 (Decrease) ----------------------------------------------------------------------------- (In millions) Incremental Expense Replacement power.............. $196 $120 $ 76 Maintenance.................... 93 115 (22) ---------------------------------------------------------------------------- Total...................... $289 $235 $ 54 ============================================================================ Incremental Net of Tax Expense... $170 $138 $32 ============================================================================ Capital Expenditures............. $ 21 $ 63 $(42) ============================================================================ FirstEnergy anticipates spending $10 million in 2004 for remaining non-capital restart activities, expected NRC inspection activities after Davis-Besse's return to service and other related activities. No additional capital expenditures related to the restoration are expected. Replacement power costs are expected to be $15-20 million per month during the remaining period of the outage. FirstEnergy has hedged the on-peak replacement energy supply for Davis-Besse for the expected length of the outage. If there are significant delays in the NRC approval process, replacement power costs will continue to be incurred, adversely affecting our cash flows and results of operations. Environmental Matters We believe we are in material compliance with current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions from the Company's Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements. We continue to evaluate our compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. 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 subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. We have been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2003, based on estimates of the total costs of cleanup, our proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. We have accrued liabilities aggregating approximately $2 million as of December 31, 2003. We do not believe environmental remediation costs will have a material adverse effect on our financial condition, cash flows or results of operations. In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but failed to receive the two-thirds vote of the U.S. Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18% through 2012. We cannot currently estimate the financial impact of climate change policies although the potential restrictions on carbon dioxide (CO2) emissions could require significant capital and other expenditures. However, the CO2 emissions 9 per kilowatt-hour of electricity generated by the Company is lower than many regional competitors due to the Company's diversified generation sources which include non-CO2 emitting nuclear generators. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. FirstEnergy continues to accumulate data and evaluate the status of its electrical system prior to and during the outage event, and continues to cooperate with the U.S.-Canada Power System Outage Task Force (Task Force) investigating the August 14th outage. The interim report issued by the Task Force on November 18, 2003 concluded that the problems leading to the outage began in FirstEnergy's service area. Specifically, the interim report concludes, among other things, that the initiation of the August 14th outage resulted from the coincidence on that afternoon of the following events: (1) inadequate situational awareness at FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its transmission rights of way; and (3) failure of the interconnected grid's reliability organizations (Midwest Independent System Operator and PJM Interconnection) to provide effective diagnostic support. FirstEnergy believes that the interim report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will correct problems identified by the Task Force as events contributing to the August 14th outage and addressing how FirstEnergy proposes to upgrade its control room computer hardware and software and improve the training of control room operators to ensure that similar problems do not occur in the future. The PUCO, in consultation with the North American Electric Reliability Council, will review the plan before determining the next steps in the proceeding. On December 24, 2003, the FERC ordered FirstEnergy to pay for an independent study of part of Ohio's power grid. The study is to examine the stability of the grid in critical points in the Cleveland and Akron areas; the status of projected power reserves during summer 2004 through 2008; and the need for new transmission lines or other grid projects. The FERC ordered the study to be completed within 120 days. At this time, it is unknown what the cost of such study will be, or the impact of the results. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against us, the most significant of which are described above. Critical Accounting Policies ---------------------------- We prepare our consolidated financial statements in accordance with accounting principles that are generally accepted in the United States (GAAP). Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Our more significant accounting policies are described below. Regulatory Accounting We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on the costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio, a significant amount of regulatory assets have been recorded - $1.1 billion as of December 31, 2003. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers 10 Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. Plan amendments to retirement health care benefits in 2003 and 2002, related to changes in benefits provided and cost-sharing provisions, which reduced FirstEnergy's obligation by $123 and $121 million, respectively. In early 2004, FirstEnergy announced that it would amend the benefit provisions of its health care benefits plan and both employees and retirees would share in more of the benefit costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% and 7.25% used as of December 31, 2002 and 2001, respectively. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by their pension trusts. In 2003, 2002 and 2001, plan assets actually earned 24.0%, (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2003 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and their pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. As a result of GPU Service Inc. merging with FirstEnergy Service Company in the second quarter of 2003, operating company employees of GPU Service were transferred to the former GPU operating companies. Accordingly, FirstEnergy requested an actuarial study to update the pension liabilities for each of its subsidiaries. Based on the actuary's report, our accrued pension costs as of June 30, 2003 decreased by $17 million. The corresponding adjustment related to this change increased other comprehensive income and deferred income taxes and decreased the payable to associated companies. Due to the increased market value of our pension plan assets, we reduced our minimum liability as prescribed by SFAS 87 as of December 31, 2003 by $12 million, recording a decrease of $4 million in an intangible asset and crediting OCI by $5 million (offsetting previously recorded deferred tax benefits by $3 million). The remaining balance in OCI of $25 million will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation. The accrued pension cost was reduced to $33 million as of December 31, 2003. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund their pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. FirstEnergy's pension and OPEB expenses in 2004 are expected to decrease by $38 million and $34 million, respectively. These reductions reflect the actual performance of pension plan assets and amendments to the health care benefits plan announced in early 2004 which result in employees and retirees sharing more of the benefit costs. The reduction in OPEB costs for 2004 does not reflect the impact of the new Medicare law signed by President Bush in December 2003 due to uncertainties regarding some of its new provisions (see Note 1(I)). The 2003 and 2002 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining their trend rate assumptions, FirstEnergy included the specific provisions of their health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in their health care plans, and projections of future medical trend rates. The effect on FirstEnergy's pension and OPEB costs and liabilities from changes in key assumptions are as follows: 11 Increase in Costs from Adverse Changes in Key Assumptions ------------------------------------------------------------------------------ Assumption Adverse Change Pension OPEB Total ------------------------------------------------------------------------------ (In millions) Discount rate................ Decrease by 0.25% $ 10 $ 5 $ 15 Long-term return on assets... Decrease by 0.25% $ 8 $ 1 $ 9 Health care trend rate....... Increase by 1% na $26 $ 26 Increase in Minimum Liability ----------------------------- Discount rate................ Decrease by 0.25% $104 na $104 ------------------------------------------------------------------------------- Ohio Transition Cost Amortization In connection with our Ohio transition plan, the PUCO determined allowable transition costs based on amounts recorded on our regulatory books. These costs exceeded those deferred or capitalized on our balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). We use an effective interest method for amortizing transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan. In computing the transition cost amortization, we include only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were indicated, we would recognize a loss - calculated as the difference between the implied fair value of our goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2003, with no impairment of goodwill indicated. The forecasts used in our evaluation of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. As of December 31, 2003, we had approximately $1.7 billion of goodwill. Nuclear Decommissioning In accordance with SFAS No. 143, we recognize an ARO for the future decommissioning of our nuclear power plants. The ARO liability represents an estimate of the fair value of our current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. We used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements") to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS ADOPTED FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FASB Interpretation No. 46, "Consolidation of Variable Interest Entities", referred to 12 as "FIN 46R", requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, we adopted FIN 46R for interests in VIEs or potential VIEs commonly referred to as special-purpose entities effective December 31, 2003. We will adopt FIN 46R for all other types of entities effective March 31, 2004. We currently have transactions with entities in connection with sale and leaseback arrangements which fall within the scope of this interpretation and which meet the definition of a VIE in accordance with FIN 46R. In 1997, the Company and The Toledo Edison Company (TE), an affiliated company, established the Shippingport Capital Trust (Shippingport) to purchase all of the lease obligation bonds issued by the owner trusts in the Bruce Mansfield Plant sale and leaseback transactions. Prior to the adoption of FIN 46R, the assets and liabilities of the trust were included on a proportionate basis in the financial statements of the Company and TE. Upon adoption of FIN 46R, we were determined to be the primary beneficiary of Shippingport, and therefore consolidated the entire trust as of December 31, 2003. As a result, Shippingport's note payable to TE of approximately $208 million ($9 million current) is recognized as long-term debt on our Consolidated Balance Sheets. In reviewing the sale and leaseback arrangements, the Company also evaluated its interest in the owner trusts that acquired interests in the Bruce Mansfield Plant. The Company was determined not to be the primary beneficiary of any of these owner trusts and was therefore not required to consolidate these entities. The leases are accounted for as operating leases in accordance with GAAP and their related obligations are disclosed in Note 2. As described in Note 3(F), we created a statutory business trust to issue trust preferred securities in the amount of $100 million. Application of the guidance in FIN 46R resulted in the holders of the preferred securities being considered the primary beneficiaries of these trusts. Therefore, we have deconsolidated the trust and recognized an equity investment in the trust of $3 million and subordinated debentures to the trust of $103 million as of December 31, 2003. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the beginning of the first interim period beginning after June 15, 2003 for all other financial instruments. Upon adoption of SFAS 150, effective July 1, 2003, we reclassified as debt the preferred stock subject to mandatory redemption with a carrying value of approximately $5 million as of December 31, 2003. Dividends on preferred stock subject to mandatory redemption on our Consolidated Statements of Income, which were not included in net interest charges prior to the adoption of SFAS 150, are now included in net interest charges for the six months ended December 31, 2003. SFAS 143, "Accounting for Asset Retirement Obligations" In January 2003, we implemented SFAS 143 which provides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an asset retirement obligation in the period in which it is incurred. See Notes 1(F) and 1(M) for further discussions of SFAS 143. EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments" In November 2003, the EITF reached consensus that certain quantitative and qualitative disclosures are required for debt and equity securities classified as available-for-sale or held-to-maturity. The guidance requires the disclosure of the aggregate amount of unrealized losses and the aggregate related fair value for investments with unrealized losses that have not been recognized as other-than-temporary impairments. We adopted the disclosure requirements of EITF Issue No. 03-1 as of December 31, 2003 (See Note 1(K)). 13
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2003 2002 2001 -------------------------------------------------------------------------------------------------------------- (In thousands) OPERATING REVENUES (Note 1(J)).............................. $1,720,784 $1,843,671 $2,064,622 ---------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel and purchased power (Note 1(J))..................... 595,279 587,108 768,306 Nuclear operating costs (Note 1(J))...................... 240,971 207,313 108,587 Other operating costs (Note 1(J))........................ 236,408 279,242 262,745 ---------- ---------- ---------- Total operation and maintenance expenses............... 1,072,658 1,073,663 1,139,638 Provision for depreciation and amortization.............. 198,307 244,727 304,417 General taxes............................................ 136,434 147,804 144,948 Income taxes............................................. 58,237 71,325 121,197 ---------- ---------- ---------- Total operating expenses and taxes..................... 1,465,636 1,537,519 1,710,200 ---------- ---------- ---------- OPERATING INCOME............................................ 255,148 306,152 354,422 OTHER INCOME (Note 6)....................................... 97,785 15,971 13,292 ---------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES.......................... 352,933 322,123 367,714 ---------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt............................... 157,967 179,140 191,695 Allowance for borrowed funds used during construction........................................... (8,232) (4,331) (2,293) Other interest expense................................... 1,665 1,462 32 Subsidiary's preferred stock dividend requirements....... 4,500 8,900 375 ---------- ---------- ---------- Net interest charges..................................... 155,900 185,171 189,809 ---------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................................... 197,033 136,952 177,905 Cumulative effect of accounting change (net of income taxes of $30,168,000) (Note 1(M))........................ 42,378 -- -- ---------- ---------- ---------- NET INCOME.................................................. 239,411 136,952 177,905 PREFERRED STOCK DIVIDEND REQUIREMENTS............................................. 7,526 15,690 24,838 ---------- ---------- ---------- EARNINGS ON COMMON STOCK.................................... $ 231,885 $ 121,262 $ 153,067 ========== ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS As of December 31, 2003 2002 ------------------------------------------------------------------------------------------------------------------ (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $4,232,335 $4,045,465 Less-Accumulated provision for depreciation.................................... 1,857,588 1,778,085 ---------- ---------- 2,374,747 2,267,380 ---------- ---------- Construction work in progress- Electric plant............................................................... 159,897 153,104 Nuclear fuel................................................................. 21,338 45,354 ---------- ---------- 181,235 198,458 ---------- ---------- 2,555,982 2,465,838 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Investment in lessor notes (Note 2)............................................ 605,915 435,907 Nuclear plant decommissioning trusts........................................... 313,621 230,527 Long-term notes receivable from associated companies........................... 107,946 102,978 Other.......................................................................... 23,636 21,004 ---------- ---------- 1,051,118 790,416 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 24,782 30,382 Receivables- Customers.................................................................... 10,313 11,317 Associated companies......................................................... 40,541 74,002 Other (less accumulated provisions of $1,765,000 and $1,015,000, respectively, for uncollectible accounts).................................. 185,179 134,375 Notes receivable from associated companies..................................... 482 447 Materials and supplies, at average cost- Owned........................................................................ 50,616 18,293 Under consignment............................................................ -- 38,094 Prepayments and other.......................................................... 4,511 4,217 ---------- ---------- 316,424 311,127 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 1,056,050 1,145,005 Goodwill....................................................................... 1,693,629 1,693,629 Property taxes................................................................. 77,122 79,430 Other.......................................................................... 23,123 24,798 ---------- ---------- 2,849,924 2,942,862 ---------- ---------- $6,773,448 $6,510,243 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity.................................................... $1,778,827 $1,200,001 Preferred stock- Not subject to mandatory redemption.......................................... 96,404 96,404 Subject to mandatory redemption (Note 3(E)).................................. -- 5,021 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures (Note 7)..... -- 100,000 Long-term debt and other long-term obligations- Preferred stock subject to mandatory redemption (Note 3(E)).................. 4,014 -- Subordinated debentures to affiliated trusts................................. 103,093 -- Notes payable to associated companies........................................ 198,843 -- Other........................................................................ 1,578,693 1,975,001 ---------- ---------- 3,759,874 3,376,427 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock........................... 387,414 388,190 Accounts payable- Associated companies......................................................... 245,815 267,664 Other........................................................................ 7,342 14,583 Notes payable to associated companies.......................................... 188,156 288,583 Accrued taxes................................................................. 202,522 126,261 Accrued interest............................................................... 37,872 51,767 Lease market valuation liability............................................... 60,200 60,200 Other.......................................................................... 76,722 64,624 ---------- ---------- 1,206,043 1,261,872 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes.............................................. 486,048 407,297 Accumulated deferred investment tax credits.................................... 65,996 70,803 Nuclear plant decommissioning costs............................................ -- 242,511 Asset retirement obligation.................................................... 254,834 -- Retirement benefits............................................................ 105,101 171,968 Lease market valuation liability............................................... 728,400 788,600 Other.......................................................................... 167,152 190,765 ---------- ---------- 1,807,531 1,871,944 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 2 and 5)................................................................ ---------- ---------- $6,773,448 $6,510,243 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION As of December 31, 2003 2002 --------------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, without par value, authorized 105,000,000 shares 79,590,689 shares outstanding.................................................... $1,281,962 $ 981,962 Accumulated other comprehensive income (loss) (Note 3(G)).......................... 2,653 (44,284) Retained earnings (Note 3(A))...................................................... 494,212 262,323 ---------- ---------- Total common stockholder's equity................................................ 1,778,827 1,200,001 ---------- ---------- Number of Shares Optional Outstanding Redemption Price ---------------- --------------------- 2003 2002 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK (NOTE 3(C)): 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 Adjustable Series L................ 474,000 474,000 100.00 47,400 46,404 46,404 --------- --------- ------- ---------- ---------- Total Not Subject to Mandatory Redemption......................... 974,000 974,000 $97,900 96,404 96,404 ========= ========= ======= ---------- ---------- Subject to Mandatory Redemption (Note 3(E)): $ 7.35 Series C**................. -- 60,000 -- 6,021 Redemption Within One Year**......... -- (1,000) --------- --------- ---------- ---------- Total Subject to Mandatory Redemption -- 60,000 -- 5,021 ========= ========= ---------- ---------- COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES (Note 3(F)): Cumulative, $25 stated value- Authorized 4,000,000 shares Subject to Mandatory Redemption: 9.00%.............................. -- 4,000,000 -- $ -- -- 100,000 ========= ========= ======= ---------- ---------- LONG-TERM DEBT (Note 3(D)): First mortgage bonds: 7.375% due 2003................................................................... -- 100,000 9.500% due 2005................................................................... -- 300,000 6.860% due 2008................................................................... 125,000 125,000 9.000% due 2023................................................................... -- 150,000 ---------- ---------- Total first mortgage bonds...................................................... 125,000 675,000 ---------- ---------- Unsecured notes: 6.000% due 2013................................................................... 78,700 78,700 5.650% due 2013................................................................... 300,000 -- 9.000% due 2031................................................................... 103,093 -- * 5.580% due 2033................................................................... 27,700 27,700 ---------- ---------- 509,493 106,400 7.682% due to associated companies 2005-2016 (Note 7)............................. 198,843 -- ---------- ---------- Total unsecured notes........................................................... 708,336 106,400 ---------- ----------
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd) As of December 31, 2003 2002 --------------------------------------------------------------------------------------------------------------------- (In thousands) LONG-TERM DEBT (Cont'd): Secured notes: 7.000% due 2004-2009............................................................. 1,730 1,760 7.750% due 2003.................................................................. -- 15,000 7.670% due 2004.................................................................. 280,000 280,000 7.130% due 2007.................................................................. 120,000 120,000 7.430% due 2009.................................................................. 150,000 150,000 * 1.120% due 2015.................................................................. 39,835 39,835 7.880% due 2017.................................................................. 300,000 300,000 * 1.120% due 2018.................................................................. 72,795 72,795 * 1.150% due 2020.................................................................. 47,500 47,500 6.000% due 2020.................................................................. 62,560 62,560 6.100% due 2020.................................................................. 70,500 70,500 9.520% due 2021.................................................................. 7,500 7,500 6.850% due 2023.................................................................. -- 30,000 8.000% due 2023.................................................................. 46,100 46,100 7.625% due 2025.................................................................. 53,900 53,900 7.700% due 2025.................................................................. 43,800 43,800 7.750% due 2025.................................................................. 45,150 45,150 5.375% due 2028.................................................................. 5,993 5,993 3.400% due 2030.................................................................. 23,255 23,255 4.600% due 2030.................................................................. -- 81,640 * 1.150% due 2033.................................................................. 30,000 30,000 ---------- ---------- Total secured notes............................................................ 1,400,618 1,527,288 ---------- ---------- Preferred stock subject to mandatory redemption**.................................. 5,014 -- ---------- ---------- Capital lease obligations (Note 2)................................................. 5,924 6,351 ---------- ---------- Net unamortized premium on debt.................................................... 27,165 47,152 ---------- ---------- Long-term debt due within one year**............................................... (387,414) (387,190) ---------- ---------- Total long-term debt and long-term obligations**............................... 1,884,643 1,975,001 ---------- ---------- TOTAL CAPITALIZATION.................................................................. $3,759,874 $3,376,427 ========== ========== * Denotes variable rate issue with December 31, 2003 interest rate shown. ** The December 31, 2003 balances for Preferred Stock subject to Mandatory Redemption is classified as debt under SFAS 150. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Accumulated Other Comprehensive Number Carrying Comprehensive Retained Income of Shares Value Income (Loss) Earnings ------------- --------- -------- ------------- -------- (Dollars in thousands) Balance, January 1, 2001....................... 79,590,689 $ 931,962 $ -- $ 163,912 Net income.................................. $177,905 177,905 Unrealized gain on instruments, net of $5,900,000 of income taxes................ 9,000 9,000 -------- Comprehensive income........................ $186,905 ======== Cash dividends on preferred stock........... (24,838) Cash dividends on common stock.............. (175,900) ------------------------------------------------------------------------------------------------------------------------ Balance, December 31, 2001..................... 79,590,689 931,962 9,000 141,079 Net income.................................. $136,952 136,952 Unrealized loss on investments, net of $(6,058,000) of income taxes.............. (9,233) (9,233) Minimum liability for unfunded retirement benefits, net of $(31,359,000) of income taxes...... (44,051) (44,051) -------- Comprehensive income........................ $ 83,668 ======== Equity contribution from parent............. 50,000 Cash dividends on preferred stock........... (10,965) Preferred stock redemption premiums......... (4,743) ------------------------------------------------------------------------------------------------------------------------ Balance, December 31, 2002..................... 79,590,689 981,962 (44,284) 262,323 Net income.................................. $239,411 239,411 Unrealized gain on investments, net of $19,598,000 of income taxes............... 28,255 28,255 Minimum liability for unfunded retirement benefits, net of $13,760,000 of income taxes..................................... 18,682 18,682 -------- Comprehensive income........................ $286,348 ======== Equity contribution from parent............. 300,000 Cash dividends on preferred stock........... (7,429) Preferred stock redemption premiums......... (93) ------------------------------------------------------------------------------------------------------------------------ Balance, December 31, 2003..................... 79,590,689 $1,281,962 $ 2,653 $ 494,212 ========================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemption ---------------------- ----------------------- Number Carrying Number Carrying of Shares Value of Shares Value --------- -------- ---------- -------- (Dollars in thousands) Balance, January 1, 2001............ 1,624,000 $238,325 177,216 $ 106,571 Issues 9.00%........................... 4,000,000 100,000 Redemptions- $ 7.35 Series C (10,000) (1,000) $88.00 Series R................. (50,000) (50,000) $91.50 Series Q................. (10,716) (10,716) $90.00 Series S................. (18,750) (18,750) Amortization of fair market value adjustments- $ 7.35 Series C ................ (11) $88.00 Series R................. (1,128) $90.00 Series S................. (668) ------------------------------------------------------------------------------------------- Balance, December 31, 2001.......... 1,624,000 238,325 4,087,750 124,298 Redemptions- $7.56 Series B................. (450,000) (45,071) $42.40 Series T................. (200,000) (96,850) $7.35 Series C................. (10,000) (1,000) $90.00 Series S................. (17,750) (17,010) Amortization of fair market value adjustments- $7.35 Series C................. (9) $90.00 Series S................. (258) ------------------------------------------------------------------------------------------- Balance, December 31, 2002.......... 974,000 96,404 4,060,000 106,021 Redemptions- $7.35 Series C................. (10,000) (1,000) FIN 46 Deconsolidation- 9.00% Series................... (4,000,000) (100,000) Amortization of fair market value adjustments- $7.35 Series C................. (7) ------------------------------------------------------------------------------------------- Balance, December 31, 2003.......... 974,000 $ 96,404 50,000 $ 5,014* =========================================================================================== * December 31, 2003 balance for preferred stock subject to mandatory redemption is classified as debt under SFAS 150 (see note 7). The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------ (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income........................................................... $ 239,411 $ 136,952 $ 177,905 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization..................... 198,307 244,727 304,417 Nuclear fuel and capital lease amortization..................... 17,466 21,044 30,539 Other amortization.............................................. (16,278) (15,008) (14,071) Deferred operating lease costs, net............................. (78,214) (60,200) (60,200) Deferred income taxes, net...................................... 27,139 3,637 32,741 Amortization of investment tax credits.......................... (4,807) (4,632) (3,770) Accrued retirement benefit obligations.......................... 7,630 (103,448) 3,837 Accrued compensation, net....................................... (8,743) 6,372 (13,886) Cumulative effect of accounting change (Note 1(M)).............. (72,546) -- -- Receivables..................................................... (16,339) (27,159) 42,542 Materials and supplies.......................................... 5,771 (7,624) 15,949 Accounts payable................................................ (54,858) 47,147 (52,068) Accrued taxes................................................... 76,261 (3,568) (48,877) Accrued interest................................................ (13,895) (5,334) 959 Prepayments and other current assets............................ (294) 27,418 27,743 Other........................................................... 58,824 56,831 (78,265) --------- --------- --------- Net cash provided from operating activities................... 364,835 317,155 365,495 --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt.................................................. 296,905 106,981 -- Preferred stock................................................. -- -- 96,739 Short-term borrowings, net...................................... -- 190,879 69,118 Equity contributions from parent................................ 300,000 50,000 -- Redemptions and Repayments- Preferred stock................................................. (1,093) (164,674) (80,466) Long-term debt.................................................. (677,097) (309,480) (74,230) Short-term borrowings, net...................................... (109,212) -- -- Dividend Payments- Common stock.................................................... -- -- (175,900) Preferred stock................................................. (7,451) (13,782) (27,645) --------- --------- --------- Net cash used for financing activities........................ (197,948) (140,076) (192,384) --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions................................................... (134,899) (163,199) (154,927) Loan payments from (to) associated companies, net.................... (5,003) 415 (10,734) Investment in lessor notes (Note 2).................................. 44,732 39,636 16,287 Sale of assets to associated companies............................... -- -- 11,117 Contributions to nuclear decommissioning trusts...................... (29,024) (29,024) (30,468) Other................................................................ (48,293) 5,179 (6,945) --------- --------- --------- Net cash used for investing activities........................ (172,487) (146,993) (175,670) --------- --------- --------- Net increase (decrease) in cash and cash equivalents................. (5,600) 30,086 (2,559) Cash and cash equivalents at beginning of year....................... 30,382 296 2,855 --------- --------- --------- Cash and cash equivalents at end of year............................. $ 24,782 $ 30,382 $ 296 ========= ========= ========= SUPPLEMENTAL CASH FLOWS INFORMATION: Cash Paid During the Year- Interest (net of amounts capitalized)........................... $ 174,375 $ 186,040 $ 196,001 ========= ========= ========= Income taxes.................................................... $ 24,796 $ 121,668 $ 131,801 ========= ========= ========= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF TAXES For the Years Ended December 31, 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: Real and personal property......................................... $ 63,448 $ 77,516 $ 72,665 State gross receipts*.............................................. -- -- 27,169 Ohio kilowatt-hour excise*......................................... 68,459 66,775 42,608 Social security and unemployment................................... 4,331 3,478 2,752 Other.............................................................. 196 35 (246) --------- --------- --------- Total general taxes......................................... $ 136,434 $ 147,804 $ 144,948 ========= ========= ========= PROVISION FOR INCOME TAXES: Currently payable- Federal......................................................... $ 109,775 $ 76,364 $ 92,739 State........................................................... 29,346 14,721 16,177 --------- --------- --------- 139,121 91,085 108,916 --------- --------- --------- Deferred, net- Federal......................................................... 21,382 (3,661) 32,368 State........................................................... 5,757 2,146 1,125 --------- --------- --------- 27,139 (1,515) 33,493 --------- --------- --------- Investment tax credit amortization................................. (4,807) (4,632) (4,522) --------- --------- --------- Total provision for income taxes............................ $ 161,453 $ 84,938 $ 137,887 ========= ========= ========= INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating income................................................... $ 58,237 $ 71,325 $ 121,197 Other income....................................................... 73,048 13,613 16,690 Cumulative effect of accounting change............................. 30,168 -- -- --------- --------- --------- Total provision for income taxes............................ $ 161,453 $ 84,938 $ 137,887 ========= ========= ========= RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes...................... $ 400,864 $ 221,890 $ 315,792 ========= ========= ========= Federal income tax expense at statutory rate....................... $ 140,302 $ 77,662 $ 110,527 Increases (reductions) in taxes resulting from- State income taxes, net of federal income tax benefit........... 22,817 10,964 11,246 Amortization of investment tax credits.......................... (4,807) (4,632) (4,522) Amortization of tax regulatory assets........................... 1,087 999 1,012 Amortization of goodwill........................................ -- -- 16,530 Other, net...................................................... 2,054 (55) 3,094 --------- --------- --------- Total provision for income taxes............................ $ 161,453 $ 84,938 $ 137,887 ========= ========= ========= ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences......................................... $ 477,358 $ 473,506 $ 463,344 Regulatory transition charge....................................... 302,270 371,486 424,484 Unamortized investment tax credits................................. (25,311) (27,839) (29,528) Deferred gain for asset sale to affiliated company................. 38,394 43,193 49,735 Other comprehensive income......................................... 1,841 (31,517) 5,900 Above market leases................................................ (324,843) (350,299) (375,333) Retirement Benefits................................................ (32,023) (42,079) (73,483) All other.......................................................... 48,362 (29,154) (51,481) --------- --------- --------- Net deferred income tax liability........................... $ 486,048 $ 407,297 $ 413,638 ========= ========= ========= * Collected from customers through regulated rates and included in revenue in the Consolidated Statements of Income. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
20 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include The Cleveland Electric Illuminating Company (Company) and its wholly owned subsidiaries, Centerior Funding Corporation (CFC), Centerior Financing Trust (CFT) and Shippingport Capital Trust (see Note 7). The Company is a wholly owned subsidiary of FirstEnergy Corp. FirstEnergy also holds directly all of the issued and outstanding common shares of its other principal electric utility operating subsidiaries, including Ohio Edison Company (OE), The Toledo Edison Company (TE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The Company follows the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The Company's consolidated financial statements for the three years ended December 31, 2002 were restated to reflect a change in the method of amortizing costs being recovered under the Ohio transition plan, recognition of above-market liabilities of certain leased generation facilities, regulatory assets and goodwill. Certain prior year amounts have been reclassified to conform with the current year presentation, as described further in Note 1(F). (A) CONSOLIDATION- The Company consolidates all majority-owned subsidiaries over which the Company exercises control and, when applicable, entities for which the Company has a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. Investments in nonconsolidated affiliates (20-50 percent owned companies, joint ventures and partnerships) over which the Company has the ability to exercise significant influence, but not control, are accounted for on the equity basis. (B) REVENUES- The Company's principal business is providing electric service to customers in northeastern Ohio. The Company's retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service provided through the end of the year. Receivables from customers include sales to residential, commercial and industrial customers located in the Company's service area and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2003 or 2002, with respect to any particular segment of the Company's customers. Total customer receivables were $10 million (billed - $6 million and unbilled - $4 million) and $11 million (billed - $8 million and unbilled - $3 million) as of December 31, 2003 and 2002, respectively. The Company and TE sell substantially all of their retail customers' receivables to CFC. CFC subsequently transfers the receivables to a trust (a Statement of Financial Accounting Standards (SFAS) No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities," - "qualified special purpose entity") under an asset-backed securitization agreement. Transfers are made in return for an interest in the trust (19% as of December 31, 2003), which is stated at fair value, reflecting adjustments for anticipated credit losses. The average collection period for billed receivables is 28 days. Given the short collection period after billing, the fair value of CFC's interest in the trust approximates the stated value of its retained interest in underlying receivables after adjusting for anticipated credit losses. Accordingly, subsequent measurements of the retained interest under SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities", (as an available-for-sale financial instrument) result in no material change in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated credit losses would not have significantly affected FirstEnergy's retained interest in the pool of receivables through the trust. Of the $250 million sold to the trust and outstanding as of December 31, 2003, FirstEnergy had a retained interest in $48 million of the receivables included as other receivables on the Consolidated Balance Sheets. Accordingly, receivables recorded on FirstEnergy's Consolidated Balance Sheets were reduced by approximately $202 million due to these sales. Collections of receivables previously transferred to the trust and used for the purchase of new receivables from CFC during 2003, totaled approximately $2.4 billion. The Company and TE processed receivables for the trust and received servicing fees of approximately $3.6 million ($2.4 million CEI and $1.2 million TE) in 2003. Expenses associated with the factoring discount related to the sale of receivables were $3.5 million, $4.7 million and $12.0 million in 2003, 2002 and 2001. 21 (C) REGULATORY MATTERS- 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 provided for a 5% 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 (market development period). 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. In July 2000, the PUCO approved FirstEnergy's transition plan for the Company, OE and TE (Ohio Companies) as modified by a settlement agreement with major parties to the transition plan. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation" to the Company's nonnuclear generation business was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $1.6 billion net of deferred income taxes and transition costs related to regulatory assets as filed of $1.4 billion net of deferred income taxes, with recovery through no later than 2008 for the Company, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $0.2 billion, net of deferred income taxes, of impaired generating assets recognized as regulatory assets as described further below, $0.4 billion, net of deferred income taxes of above market operating lease costs and $0.5 billion, net of deferred income taxes, of additional plant costs that were reflected on the Company's regulatory financial statements. Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 400 megawatts (MW) of generation capacity through 2005 at established prices for sales to the Company's retail customers. Customer prices are frozen through the five-year market development period, which runs through the end of 2005, except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Company was authorized increases in annual revenues aggregating approximately $4 million to recover its higher tax costs resulting from the Ohio deregulation legislation. The Company's customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers. Subject to approval by the PUCO, recovery will be accomplished by extending the transition cost recovery period. On October 21, 2003, the Ohio Companies filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate supply and continuing FirstEnergy's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service for the Ohio Companies' customers. Beginning in 2006, customers would pay market prices for generation as determined by the auction. Under the Rate Stabilization Plan option, customers would have price and supply stability through 2008 - three years beyond the end of the market development period - as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually to ensure that customers pay the lowest available prices; extension of the Company's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, CEI is requesting: o Extension of the transition cost amortization period from 2008 to July 2009; o Deferral of interest costs on the accumulated shopping incentive and other cost deferrals as new regulatory assets; and o Ability to initiate a request to increase generation rates only under certain limited conditions. 22 On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. A decision is expected from the PUCO in the Spring of 2004. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will address certain problems identified by the U.S.-Canada Power System Outage Task Force (in connection with the August 14, 2003 regional power outage) and addressing how FirstEnergy proposes to upgrade its control room computer hardware and software, improve its control room training procedures and improve the training of control room operators to ensure that similar problems do not occur in the future. The PUCO, in consultation with the North American Electric Reliability Council, will review the plan before determining the next steps in the proceeding. Transition Cost Amortization - The Company amortizes transition costs (see Regulatory Matters) using the effective interest method. Under the current Ohio transition plan, total transition cost amortization is expected to approximate the following for 2004 through 2009. (In millions) -------------------------------- 2004.................. $192 2005.................. 219 2006.................. 129 2007.................. 145 2008.................. 164 2009.................. 46 ------------------------------- Regulatory Assets- The Company recognizes, as regulatory assets, costs which the FERC and the PUCO have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Company's transition plan. Based on that plan, the Company continues to bill and collect cost-based rates for its transmission and distribution services, which will remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2003 2002 --------------------------------------------------------------------------- (In millions) Regulatory transition charge.................... $ 900 $1,066 Customer shopping incentives.................... 179 85 Customer receivables for future income taxes.... 7 8 Loss on reacquired debt......................... 14 16 Employee postretirement benefit costs........... 15 17 Component removal costs......................... (60) (47) Other........................................... 1 -- ------------------------------------------------------------------------- Total...................................... $1,056 $1,145 ========================================================================= Regulatory Accounting Generation Operations- The application of SFAS 71 has been discontinued with respect to the Company's generation operations. The SEC issued interpretive guidance regarding asset impairment measurement providing that any supplemental regulated cash flows such as a competitive transition charge should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance $304 million of impaired plant investments were recognized by the Company as regulatory assets recoverable as transition costs through future regulatory cash flows. Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued were $1.4 billion as of December 31, 2003. (D) UTILITY PLANT AND DEPRECIATION- Utility plant reflects the original cost of construction (except for the Company's nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and 23 general costs, and interest costs incurred to place the assets in service. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 3.0% in 2003, 3.4% in 2002 and 3.2% in 2001. Nuclear Fuel- Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Company amortizes the cost of nuclear fuel based on the rate of consumption. (E) COMMON OWNERSHIP OF GENERATING FACILITIES- The Company, together with TE, OE and OE's wholly owned subsidiary, Pennsylvania Power Company (Penn), own and/or lease, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly owned facility in the same proportion as its interest. The Company's portion of operating expenses associated with jointly owned facilities is included in the corresponding operating expenses on the Consolidated Statements of Income. The amounts reflected on the Consolidated Balance Sheet under utility plant as of December 31, 2003 include the following:
Utility Accumulated Construction Ownership/ Plant Provision for Work in Leasehold Generating Units in Service Depreciation Progress Interest ------------------------------------------------------------------------------------------ (In millions) W. H. Sammis Unit 7........... $ 180 $123 $ -- 31.20% Bruce Mansfield Units 1, 2 and 3....................... 127 43 25 20.42% Beaver Valley Unit 2.......... 13 1 14 24.47% Davis-Besse................... 248 56 84 51.38% Perry......................... 655 161 9 44.85% ------------------------------------------------------------------------------------------ Total...................... $1,223 $384 $132 . ==========================================================================================
The Bruce Mansfield Plant is being leased through a sale and leaseback transaction (see Note 2) and the above-related amounts represent construction expenditures subsequent to the transaction. (F) ASSET RETIREMENT OBLIGATION- In January 2003, the Company implemented SFAS 143, "Accounting for Asset Retirement Obligations", which provides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead if the criteria for such treatment are met. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount. The Company identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant, and closure of two coal ash disposal sites. The ARO liability as of the date of adoption of SFAS 143 was $238.3 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. Accretion during 2003 was $16.5 million, bringing the ARO liability as of December 31, 2003 to $254.8 million. The ARO includes the Company's obligation for nuclear decommissioning of the Beaver Valley Unit 2, Davis-Besse, and Perry generating facilities. The Company's share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. The Company utilized an expected cash flow approach (as discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements") to measure the fair value of the nuclear decommissioning ARO. The Company maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2003, the fair value of the decommissioning trust assets was $313.6 million. In accordance with SFAS 143, the Company ceased the accounting practice of depreciating non-regulated generation assets using a cost of removal component in the depreciation rates. That practice recognized accumulated depreciation in excess of the historical cost of an asset because the removal cost would exceed the estimated salvage value. Beginning in 2003, the cost of removal related to non-regulated generation assets is charged to expense rather than 24 to the accumulated provision for depreciation. In accordance with SFAS 71, the cost of removal on regulated plant assets continues to be accounted for as a component of depreciation rates and is recognized as a regulatory liability. The following table provides the effect on income as if SFAS 143 had been applied during 2002 and 2001. Effect of the Change in Accounting Principle Applied Retroactively 2002 2001 ----------------------------------------------------------------------------- (In millions) Reported net income........................................ $137 $178 Increase (Decrease): Elimination of decommissioning expense..................... 29 29 Depreciation of asset retirement cost...................... (1) (1) Accretion of ARO liability................................. (15) (14) Non-regulated generation cost of removal component, net.... 9 6 Income tax effect.......................................... (9) (8) ------------------------------------------------------------------------------ Net earnings increase...................................... 13 12 ----------------------------------------------------------------------------- Net income adjusted........................................ $150 $190 ============================================================================= The following table provides the year-end balance of the ARO for 2002, as if SFAS 143 had been adopted on January 1, 2002. Adjusted ARO Reconciliation 2002 -------------------------------------------------------- (In millions) Beginning balance as of January 1, 2002 $223.1 Accretion in 2002 15.2 ------------------------------------------------------ Ending balance as of December 31, 2002 $238.3 ------------------------------------------------------ (G) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 3B). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method of SFAS 123, "Accounting for Stock Compensation," a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows: 2003 2002 2001 ---------------------------------------------------------------------------- Valuation assumptions: Expected option term (years). 7.9 8.1 8.3 Expected volatility.......... 26.91% 23.31% 23.45% Expected dividend yield...... 5.09% 4.36% 5.0% Risk-free interest rate...... 3.67% 4.60% 4.6% Fair value per option.......... $5.09 $6.45 $4.97 ---------------------------------------------------------------------------- The effects of applying fair value accounting to FirstEnergy's stock options would not materially affect the Company's net income. (H) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. The Company is included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with each Company recognizing any tax losses or credits the Company contributes to the consolidated return. 25 (I) PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS- FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of the Company's employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy's funding policy is based on actuarial computations using the projected unit credit method. No pension contributions were required during the three years ended December 31, 2003. FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. FirstEnergy uses a December 31 measurement date for the majority of its plans. Plan amendments to retirement health care benefits in 2003 and 2002, relate to changes in benefits provided and cost-sharing provisions, which reduced FirstEnergy's obligation by $123 and $121 million, respectively. In early 2004, FirstEnergy announced that it would amend the benefit provisions of its health care benefits plan and both employees and retirees would share in more of the benefit costs. On December 8, 2003, President Bush signed into law a bill that expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. FirstEnergy anticipates that the benefits it pays after 2006 will be lower as a result of the new Medicare provisions. Due to uncertainties surrounding some of the new Medicare provisions and a lack of authoritative accounting guidance about these issues, FirstEnergy deferred the recognition of the impact of the new Medicare provisions as provided by FASB Staff Position 106-1. The final accounting guidance could require changes to previously reported information. The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Obligations and Funded Status Pension Benefits Other Benefits ---------------- -------------- As of December 31 2003 2002 2003 2002 ------------------------------------------------------------------------------------------ (In millions) Change in benefit obligation Benefit obligation at beginning of year.. $3,866 $3,548 $ 2,077 $ 1,582 Service cost............................. 66 59 43 28 Interest cost............................ 253 249 136 114 Plan participants' contributions......... -- -- 6 -- Plan amendments.......................... -- -- (123) (121) Actuarial loss........................... 222 268 323 440 GPU acquisition.......................... -- (12) -- 110 Benefits paid............................ (245) (246) (94) (76) ------ ------ ------- ------- Benefit obligation at end of year........ $4,162 $3,866 $ 2,368 $ 2,077 ====== ====== ======= ======= Change in fair value of plan assets Fair value of plan assets at beginning of year................................ $2,889 $3,484 $ 473 $ 535 Actual return on plan assets............. 671 (349) 88 (57) Company contribution..................... -- -- 68 31 Plan participants' contribution.......... -- -- 2 -- Benefits paid............................ (245) (246) (94) (36) ------ ------ ------- ------- Fair value of plan assets at end of year. $3,315 $2,889 $ 537 $ 473 ====== ====== ======= ======= Funded status............................ $ (847) $ (977) $(1,831) (1,604) Unrecognized net actuarial loss.......... 919 1,186 994 752 Unrecognized prior service cost (benefit).............................. 72 78 (221) (107) Unrecognized net transition obligation... -- -- 83 92 ------ ------ -------- ------- Net asset (liability) recognized......... $ 144 $ 287 $ (975) $ (867) ====== ====== ======= =======
Amounts Recognized in the Consolidated Balance Sheets As of December 31 ----------------------------------------- Accrued benefit cost..................... $ (438) $ (548) $ (975) $ (867) Intangible assets........................ 72 78 -- -- Accumulated other comprehensive loss..... 510 757 -- -- ------ ------ ------- ------- Net amount recognized.................... $ 144 $ 287 $ (975) $ (867) ====== ====== ======= ======= Company's share of net amount recognized. $ 22 $ 39 $ (71) $ (117) ====== ====== ======= ======= Increase in minimum liability included in other comprehensive income (net of tax) $ (145) $ 444 $ -- $ -- Weighted-Average Assumptions Used to Determine Benefit Obligations As of December 31 ----------------------------------------- Discount rate........................... 6.25% 6.75% 6.25% 6.75% Rate of compensation increase........... 3.50% 3.50% Allocation of Plan Assets As of December 31 ----------------------------------------- Asset Category Equity securities..................... 70% 61% 71% 58% Debt securities....................... 27 35 22 29 Real estate........................... 2 2 -- -- Other................................. 1 2 7 13 --- --- --- --- Total................................. 100% 100% 100% 100% === === === === Information for Pension Plans With an Accumulated Benefit Obligation in Excess of Plan Assets 2003 2002 ----------------------------------------- ---- ---- (In millions) Projected benefit obligation............. $4,162 $3,866 Accumulated benefit obligation........... 3,753 3,438 Fair value of plan assets................ 3,315 2,889
FirstEnergy's net pension and other postretirement benefit costs for the three years ended December 31, 2003 were computed as follows:
Pension Benefits Other Benefits ---------------------- ------------------- Components of Net Periodic Benefit Costs 2003 2002 2001 2003 2002 2001 ------------------------------------------------------------------------------------------- (In millions) Service cost............................ $ 66 $ 59 $ 35 $ 43 $ 29 $ 18 Interest cost........................... 253 249 133 137 114 65 Expected return on plan assets.......... (248) (346) (205) (43) (52) (10) Amortization of prior service cost...... 9 9 9 (9) 3 3 Amortization of transition obligation (asset)................................ -- -- (2) 9 9 9 Recognized net actuarial loss........... 62 -- -- 40 11 5 Voluntary early retirement program...... -- -- 6 -- -- 2 ----- ----- ----- ---- ---- ---- Net periodic cost (income).............. $ 142 $ (29) $ (24) $177 $114 $ 92 ===== ===== ===== ==== ==== ==== Company's share of net benefit costs (income).............................. $ 10 $ 1 $ (2) $ 15 $ 10 $ 13 ===== ===== ===== ==== ==== ==== Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount rate.......................... 6.75% 7.25% 7.75% 6.75% 7.25% 7.75% Expected long-term return on plan assets............................... 9.00% 10.25% 10.25% 9.00% 10.25% 10.25% Rate of compensation increase.......... 3.50% 4.00% 4.00%
In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. The assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the Company's pension trusts. The long-term rate of return is developed considering the portfolio's asset allocation strategy. 27 Assumed health care cost trend rates As of December 31 2003 2002 ------------------------------------------------------------------------------ Health care cost trend rate assumed for next year (pre/post-Medicare).......................... 10%-12% 10%-12% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)................. 5% 5% Year that the rate reaches the ultimate trend rate (pre/post-Medicare).......................... 2009-2011 2008-2010 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects: 1-Percentage- 1-Percentage- Point Increase Point Decrease ------------------------------------------------------------------------------- (In millions) Effect on total of service and interest cost.. $ 26 $ (19) Effect on postretirement benefit obligation... $233 $(212) FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalizations. Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies. As a result of GPU Service Inc. merging with FirstEnergy Service Company in the second quarter of 2003, operating company employees of GPU Service were transferred to the former GPU operating companies. Accordingly, FirstEnergy requested an actuarial study to update the pension liabilities for each of its subsidiaries. Based on the actuary's report, the accrued pension costs for the Company as of June 30, 2003 decreased by $17 million. The corresponding adjustment related to this change increased other comprehensive income and deferred income taxes and decreased the payable to associated companies. Due to the increased market value of its pension plan assets, the Company reduced its minimum liability as prescribed by SFAS 87 as of December 31, 2003 by $12 million, recording a decrease of $4 million in an intangible asset and crediting OCI by $5 million (offsetting previously recorded deferred tax benefits by $3 million). The remaining balance in OCI of $25 million will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation. The accrued pension cost was reduced to $33 million as of December 31, 2003. FirstEnergy does not expect to contribute to its pension plans in 2004 and expects to contribute $16 million to its other postretirement benefit plans in 2004. (J) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily ATSI, FirstEnergy Solutions Corp. (FES) and FirstEnergy Service Company (FESC). The Ohio transition plan, as discussed in the "Regulatory Matters" section, resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. FES operates the generation businesses of the Company, TE, OE and Penn. As a result, the Company entered into power supply agreements (PSA) whereby FES purchases all of the Company's nuclear generation and the generation from leased fossil generating facilities and the Company purchases its power from FES to meet its "provider of last resort" obligations. CFC serves as the transferor in connection with the accounts receivable securitization for the Company and TE. The primary affiliated companies transactions are as follows: 28 2003 2002 2001 ------------------------------------------------------------------------------ (In millions) Operating Revenues: PSA revenues from FES............ $260 $284 $334 Generating units rent from FES... 59 60 59 Ground lease with ATSI........... 7 7 7 Operating Expenses: Purchased power under PSA........ 423 420 597 Purchased power from TE.......... 109 104 97 Transmission expenses............ 32 41 29 FESC support services............ 63 52 50 Other Income: Interest income from ATSI........ 7 7 7 Interest income from FES......... 1 1 1 --------------------------------------------------------------------------- The Company is buying 150 MW of TE's Beaver Valley Unit 2 leased capacity entitlement. Purchased power expenses for this transaction were $109 million, $104 million and $97 million in 2003, 2002 and 2001, respectively. This purchase is expected to continue through the end of the lease period (see Note 2). FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from FESC, a subsidiary of FirstEnergy and a "mutual service company" as defined in Rule 93 of the Public Utility Holding Company Act of 1935 (PUHCA). The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas; each company's proportionate amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with FirstEnergy and its other subsidiaries are generally settled under commercial terms within thirty days, except for $145 million payable to affiliates for pension and OPEB obligations. (K) CASH AND FINANCIAL INSTRUMENTS- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Cash and cash equivalents included $25 million received in December 2003 which was included in the NRG settlement claim sold in January 2004 (see Note 6) and $30 million used for the redemption of long-term debt in January 2003 as of December 31, 2003 and 2002, respectively. Noncash financing and investing activities included capital lease transactions amounting to $2.1 million in 2001. There were no capital lease transactions in 2003 or 2002. "Other amortization" on the Consolidated Statement of Cash Flows under Cash Flows from Operating Activities consists of amounts from the reduction of an electric service obligation under the Company's electric service prepayment program. 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:
2003 2002 ---------------------------------------------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value ---------------------------------------------------------------------------------------------------------- (In millions) Long-term debt................................... $2,234 $2,444 $2,309 $2,493 Preferred stock*................................. $ 5 $ 5 $ 106 $ 113 Investments other than cash and cash equivalents: Debt securities - Maturity (5-10 years)....................... $ 11 $ 11 $ 11 $ 11 - Maturity (more than 10 years)............... 698 812 528 576 All other..................................... 318 318 232 232 ---------------------------------------------------------------------------------------------------------- $1,027 $1,141 $ 771 $ 819 ========================================================================================================== * The December 31, 2003 amount is classified as debt under SFAS 150.
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 Company's ratings. 29 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. The Company has no securities held for trading purposes. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "All other" in the table above) consist of equity securities ($188 million) and fixed income securities ($124 million) as of December 31, 2003. Unrealized gains and losses applicable to the Company's decommissioning trusts are recognized in the trust investment with a corresponding offset to OCI, as fluctuations in the fair value of the trusts will eventually affect earnings. Realized gains (losses) are recognized as additions (reductions) to trust asset balances with an offset to earnings. For 2003 and 2002, net realized losses were approximately $0.8 million and $6.9 million, respectively, and interest and dividend income totaled approximately $8.5 million and $7.3 million, respectively. Investments other than cash and cash equivalents in the table above include available-for-sale securities, at fair value, with the following net results: 2003* 2002* ---------------------------------------------------------------- (In millions) Unrealized gains (losses)........... $ 48.1 $(15.3) Proceeds from sales................. 226.0 197.8 Realized gains (losses)............. (0.8) (6.9) ---------------------------------------------------------------- * Includes the available-for-sale securities of the Company's decommissioning trusts. As of December 31, 2003 accumulated other comprehensive income (loss) for available-for-sale securities consisted of investments with net unrealized gains of $59.8 million and net unrealized losses of $12.1 million. The following table provides details for the available-for-sale securities with net unrealized losses as of December 31, 2003.
Less Than 12 Months 12 Months or More Total -------------------- -------------------- --------------------- Fair Unrealized Fair Unrealized Fair Unrealized Security Type Value Losses Value Losses Value Losses ------------------------------------------------------------------------------------------------------- (In millions) Equity Securities....... $ 7.8 $2.3 $11.2 $9.6 $19.0 $11.9 Debt Securities......... 10.2 0.2 -- -- 10.2 0.2 ----------------------------------------------------------------------------------------------------- Total............... $18.0 $2.5 $11.2 $9.6 $29.2 $12.1 -------------------------------------------------------------------------------------------------------
All of the aggregate unrealized losses related to available-for-sale securities in the table above are considered to be temporary in nature. These securities are primarily held by the Company's nuclear decommissioning trusts. The Company has the ability and intent to hold these securities for the period necessary to fund their cost. (L) GOODWILL- In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Under SFAS 142, "Goodwill and Other Intangible Assets," amortization of existing goodwill ceased January 1, 2002. Instead, the Company evaluates its goodwill for impairment at least annually and makes such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. When impairment is indicated, the Company would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. The Company's annual review was completed in the third quarter of 2003, with no impairment of goodwill indicated. The forecasts used in the Company's evaluation of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of December 31, 2003, the Company had approximately $1.7 billion of goodwill. The impairment analysis includes a significant source of cash representing the Company's recovery of transition costs as described above under "Regulatory Matters." The Company does not believe that completion of transition cost recovery will result in an impairment of goodwill. 30 The following table shows what net income would have been if goodwill amortization had been excluded from prior periods: 2003 2002 2001 ---- ---- ---- (In thousands) Reported net income................ $239,411 $136,952 $177,905 Add back goodwill amortization..... -- -- 47,230 -------- -------- -------- Adjusted net income................ $239,411 $136,952 $225,135 ======== ======== ======== (M) CUMULATIVE EFFECT OF ACCOUNTING CHANGE- Results for 2003 include an after-tax credit to net income of $42.4 million recorded by the Company upon adoption of SFAS 143 in January of 2003. The Company identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $49.9 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $6.8 million. The asset retirement obligation liability at the date of adoption was $238.3 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, the Company had recorded decommissioning liabilities of $242.5 million. The cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $72.5 million increase to income, or $42.4 million net of income taxes. 2. LEASES: The Company leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. The Company and TE sold their ownership interests in Bruce Mansfield Units 1, 2 and 3 and TE sold a portion of its ownership interest in Beaver Valley Unit 2. In connection with these sales, which were completed in 1987, the Company and TE entered into operating leases for lease terms of approximately 30 years as co-lessees. During the terms of the leases, the Company and TE continue to be responsible, to the extent of their combined ownership and leasehold interest, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company and TE have the right, at the end of the respective basic lease terms, to renew the leases. The Company and TE also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. As co-lessee with TE, the Company is also obligated for TE's lease payments. If TE is unable to make its payments under the Beaver Valley Unit 2 and Bruce Mansfield Plant leases, the Company would be obligated to make such payments. No such payments have been made on behalf of TE. (TE's future minimum lease payments as of December 31, 2003 were approximately $1.0 billion, net of trust cash receipts.) Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2003 are summarized as follows: 2003 2002 2001 ------------------------------------------------------------------ (In millions) Operating leases Interest element...... $31.6 $33.6 $35.3 Other................. 45.9 42.8 36.4 Capital leases Interest element...... 0.6 0.6 3.6 Other................. 0.4 0.4 19.4 ------------------------------------------------------------------ Total rentals......... $78.5 $77.4 $94.7 ================================================================== 31 The future minimum lease payments as of December 31, 2003 are:
Operating Leases ------------------------------------ Capital Lease Capital Leases Payments Trust Net --------------------------------------------------------------------------------------------- (In millions) 2004.................................. $ 1.0 $ 55.7 $ 28.6 $ 27.1 2005.................................. 1.0 66.7 48.3 18.4 2006.................................. 1.0 71.3 56.2 15.1 2007.................................. 1.0 57.8 48.2 9.6 2008.................................. 1.0 54.2 42.9 11.3 Years thereafter...................... 3.7 470.5 350.4 120.1 ---------------------------------------------------------------------------------------------- Total minimum lease payments.......... 8.7 $776.2 $574.6 $201.6 ====== ====== ====== Interest portion...................... 2.8 ------------------------------------------------- Present value of net minimum lease payments...................... 5.9 Less current portion.................. 0.4 ------------------------------------------------- Noncurrent portion.................... $ 5.5 =================================================
The Company has recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger creating FirstEnergy. The total above-market lease obligation of $611 million associated with Beaver Valley Unit 2 is being amortized on a straight-line basis through the end of the lease term in 2017 (approximately $31 million per year). The total above-market lease obligation of $457 million associated with the Bruce Mansfield Plant is being amortized on a straight-line basis through the end of 2016 (approximately $29 million per year). As of December 31, 2003 the above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled approximately $789 million, of which $60 million is current. The Company and TE refinanced high-cost fixed obligations related to their 1987 sale and leaseback transaction for the Bruce Mansfield Plant through a lower cost transaction in June and July 1997. In a June 1997 offering (Offering), the two companies pledged $720 million aggregate principal amount ($575 million for the Company and $145 million for TE) of first mortgage bonds due through 2007 to a trust as security for the issuance of a like principal amount of secured notes due through 2007. The obligations of the two companies under these secured notes are joint and several. Using available cash, short-term borrowings and the net proceeds from the Offering, the two companies invested $906.5 million ($569.4 million for the Company and $337.1 million for TE) in a business trust, in June 1997. The trust used these funds in July 1997 to purchase lease notes and redeem all $873.2 million aggregate principal amount of 10-1/4% and 11-1/8% secured lease obligation bonds (SLOBs) due 2003 and 2016. The SLOBs were issued by a special-purpose-funding corporation in 1988 on behalf of lessors in the two companies' 1987 sale and leaseback transaction. The Shippingport arrangement effectively reduces lease costs related to that transaction (see Note 7 for FIN 46R discussion). 3. CAPITALIZATION: (A) RETAINED EARNINGS- There are no restrictions on retained earnings for payment of cash dividends on the Company's common stock. (B) STOCK COMPENSATION PLANS- FirstEnergy administers the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Several other stock compensation plans have been acquired through the mergers with GPU and Centerior - GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan), 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan) and Centerior Equity Plan. No further stock-based compensation can be awarded under these plans. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 32 2003 2002 2001 --------------------------------------------------------------------------- Restricted common shares granted...... -- 36,922 133,162 Weighted average market price ........ n/a (1) $36.04 $35.68 Weighted average vesting period (years)............................. n/a (1) 3.2 3.7 Dividends restricted.................. n/a (1) Yes -- (2) --------------------------------------------------------------------------- (1) Not applicable since no restricted stock was granted. (2) FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2003, there were 410,399 stock units outstanding. Stock option activities under the FE Programs for the past three years were as follows: Number of Weighted Average Stock Option Activities Options Exercise Price ----------------------------------------------------------------------------- Balance, January 1, 2001.............. 5,021,862 24.09 (473,314 options exercisable)......... 24.11 Options granted..................... 4,240,273 28.11 Options exercised................... 694,403 24.24 Options forfeited................... 120,044 28.07 Balance, December 31, 2001............ 8,447,688 26.04 (1,828,341 options exercisable)....... 24.83 Options granted..................... 3,399,579 34.48 Options exercised................... 1,018,852 23.56 Options forfeited................... 392,929 28.19 Balance, December 31, 2002............ 10,435,486 28.95 (1,400,206 options exercisable)....... 26.07 Options granted..................... 3,981,100 29.71 Options exercised................... 455,986 25.94 Options forfeited................... 311,731 29.09 Balance, December 31, 2003............ 13,648,869 29.27 (1,919,662 options exercisable)....... 29.67 As of December 31, 2003, the weighted average remaining contractual life of outstanding stock options was 7.6 years. Options outstanding by plan and range of exercise price as of December 31, 2003 were as follows: Range of Options FirstEnergy Program Exercise Prices Outstanding ----------------------------------------------------------------------- FE plan $19.31 - $29.87 9,904,861 $30.17 - $35.15 3,214,601 Plans acquired through merger: GPU plan $23.75 - $35.92 501,734 Other plans 27,673 ---------------------------------------------------------------------- Total 13,648,869 ====================================================================== No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 1G - "Stock-Based Compensation." 33 (C) PREFERRED AND PREFERENCE STOCK- The Company's preferred stock may be redeemed in whole, or in part, with 30-90 days' notice. The preferred dividend rate on the Company's Series L fluctuates based on prevailing interest rates and market conditions. The dividend rate for this issue was 7% in 2003. The Company has three million authorized and unissued shares of preference stock having no par value. (D) LONG-TERM DEBT- The Company has a first mortgage indenture under which it issues first mortgage bonds secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios covenants. There also exists cross-default provisions among financing agreements of FirstEnergy and the Company. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) ---------------------------------------------- 2004................................ $386 2005................................ 10 2006................................ 12 2007................................ 129 2008................................ 140 --------------------------------------------- Included in the table above are amounts for various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. The amount is $98.5 million in 2004, which represents the next time debt holders may exercise this provision. The Company's obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of an irrevocable bank letter of credit of $48.1 million and a noncancelable municipal bond insurance policy of $30.0 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letter of credit or policies, the Company is entitled to a credit against its obligation to repay that bond. The Company pays an annual fee of 1.125% of the amount of the letter of credit to the issuing bank and is obligated to reimburse the bank for any drawings thereunder. The Company and TE have unsecured letters of credit of approximately $215.9 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. The Company and TE are jointly and severally liable for the letters of credit (see Note 2). (E) LONG-TERM DEBT: PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- Effective July 1, 2003, upon adoption of SFAS 150 (see Note 7), the Company reclassified as debt its preferred stock subject to mandatory redemption. Prior year amounts were not reclassified. The Company's $7.35 C series has an annual sinking fund requirement for 10,000 shares with annual sinking fund requirements for the next five years of $1.0 million in each year 2004-2008. (F) LONG-TERM DEBT: SUBORDINATED DEBENTURES TO AFFILIATED TRUSTS- The Company formed a wholly owned statutory business trust to sell preferred securities and invest the gross proceeds in the 9.00% subordinated debentures of the Company. The sole assets of the trust are the applicable subordinated debentures. Interest payment provisions of the subordinated debentures match the distribution payment provisions of the trust's preferred securities. In addition, upon redemption or payment at maturity of subordinated debentures, the trust's preferred securities will be redeemed on a pro rata basis at their liquidation value. Under certain circumstances, the applicable subordinated debentures could be distributed to the holders of the outstanding preferred securities of the trust in the event that the trust is liquidated. The Company has effectively provided a full and unconditional guarantee of payments due on the trust's preferred securities. The trust's preferred securities are redeemable at 100% of their principal amount at the Company's option beginning in December 2006. 34 Interest on the subordinated debentures (and therefore distributions on the trust's preferred securities) may be deferred for up to 60 months, but the Company may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full. Upon adoption of FIN 46R, the statutory business trust discussed above is not consolidated on the Company's financial statements as of December 31, 2003 (see Note 7). (G) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with FirstEnergy. As of December 31, 2003, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $(25.4) million and unrealized gains on investments in securities available for sale of $28.0 million. 4. SHORT-TERM BORROWINGS: The Company may borrow from its affiliates on a short-term basis. As of December 31, 2003, the Company had total short-term borrowings of $188.2 million from its affiliates. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2003 and 2002, were 2.2% and 1.8%, respectively. 5. COMMITMENTS AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $275 million for property additions and improvements from 2004-2006, of which approximately $92 million is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $61 million, of which approximately $29 million applies to 2004. During the same periods, the Company's nuclear fuel investments are expected to be reduced by approximately $60 million and $30 million, respectively, as the nuclear fuel is consumed. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.9 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its ownership and leasehold interests in Beaver Valley Unit 2, the Davis-Besse Station and the Perry Plant, the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $121.4 million per incident but not more than $12.1 million in any one year for each incident. The Company is also insured as to its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $382 million of insurance coverage for replacement power costs for its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry. Under these policies, the Company can be assessed a maximum of approximately $20.5 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Company's plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs. (C) ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. The effects of compliance on the Company with regard to environmental matters could have a material adverse effect on the Company's earnings and competitive position. These environmental regulations affect the Company's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, the Company believes it is in material compliance with existing regulations but are unable to predict future change in regulatory policies and what, if any, the effects of such change would be. In accordance with the Ohio 35 transition plan discussed in "Regulatory Matters" in Note 1(C), generation operations and any related additional capital expenditures for environmental compliance are the responsibility of FirstEnergy's competitive services business unit. Clean Air Act Compliance The Company is required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Company cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Company is complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Company's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that required compliance with the NOx budgets at the Company's Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Company's Ohio facilities by May 31, 2004. The Company's Pennsylvania facilities complied with the NOx budgets in 2003 and all facilities will comply with the NOx budgets in 2004 and thereafter. National Ambient Air Quality Standards In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone and proposed a new NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NOx and SO2 emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO2 emissions would be reduced by approximately 3.6 million tons in 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend if and how they are ultimately implemented by the states in which the Company operates affected facilities. Mercury Emissions In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as "maximum achievable control technologies" (MACT) based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by fourteen tons to approximately thirty-four tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at fifteen tons per year. The EPA has agreed to choose between these two options and issue a final rule by December 15, 2004. The future cost of compliance with these regulations may be substantial. Regulation of Hazardous Waste 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 subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. 36 The Company has 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; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2003, based on estimates of the total costs of cleanup, the Company's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. The Company has total accrued liabilities aggregating approximately $2 million as of December 31, 2003. The Company accrues environmental liabilities only when it can conclude that it is probable that it has an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in the Company's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Climate Change In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the U.S. Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18% through 2012. The Company cannot currently estimate the financial impact of climate change policies although the potential restrictions on carbon dioxide (CO2) emissions could require significant capital and other expenditures. However, the CO2 emissions per kilowatt-hour of electricity generated by the Company is lower than many regional competitors due to the Company's diversified generation sources which includes low or non-CO2 emitting gas-fired and nuclear generators. Clean Water Act Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to the Company's plants. In addition, Ohio and Pennsylvania have water quality standards applicable to the Company's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio and Pennsylvania have assumed such authority. (D) LEGAL MATTERS AND OTHER CONTINGENCIES Various lawsuits, claims and proceedings related to the Company's normal business operations are pending against FirstEnergy and its subsidiaries. On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. FirstEnergy continues to accumulate data and evaluate the status of its electrical system prior to and during the outage event, and continues to cooperate with the U.S.-Canada Power System Outage Task Force (Task Force) investigating the August 14th outage. The interim report issued by the Task Force on November 18, 2003 concluded that the problems leading to the outage began in FirstEnergy's service area. Specifically, the interim report concludes, among other things, that the initiation of the August 14th outage resulted from the coincidence on that afternoon of the following events: (1) inadequate situational awareness at FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its transmission rights of way; and (3) failure of the interconnected grid's reliability organizations (Midwest Independent System Operator and PJM Interconnection) to provide effective diagnostic support. FirstEnergy believes that the interim report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will correct problems identified by the Task Force as events contributing to the August 14th outage and addressing how FirstEnergy proposes to upgrade its control room computer hardware and software and improve the training of control room operators to ensure that similar problems do not occur in the future. The PUCO, in consultation with the North American Electric Reliability Council, will review the plan before determining the next steps in the proceeding. On December 24, 2003, the FERC ordered FirstEnergy to pay for an independent study of part of Ohio's power grid. The study is to examine the stability of the grid in critical points in the Cleveland and Akron areas; the status of projected power reserves during summer 2004 through 2008; and the need for new transmission lines or other grid projects. The FERC ordered the study to be completed within 120 days. At this time, it is unknown what the cost of such study will be, or the impact of the results. 37 6. SALE OF GENERATING ASSETS: In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 MW to NRG Energy Inc. The proposed sale had included the 376 MW Ashtabula, 1,262 MW Eastlake and 249 MW Lakeshore plants owned by the Company. On August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. NRG filed voluntary bankruptcy petitions in May 2003; subsequently, FirstEnergy reached an agreement for settlement of its claim against NRG. FirstEnergy sold its entire claim for $170 million (Company's share - $131 million) in January 2004. In December 2002, FirstEnergy decided to retain ownership of these plants after reviewing other bids it subsequently received from other parties who had expressed interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, the Company reflected approximately $45 million ($26 million net of tax) of previously unrecognized depreciation and other transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statement of Income. 7. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS: FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FASB Interpretation No. 46, "Consolidation of Variable Interest Entities", referred to as "FIN 46R", requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, the Company adopted FIN 46R for interests in VIEs or potential VIEs commonly referred to as special-purpose entities effective December 31, 2003. the Company will adopt FIN 46R for all other types of entities effective March 31, 2004. The Company currently has transactions with entities in connection with sale and leaseback arrangements which fall within the scope of this interpretation and which meet the definition of a VIE in accordance with FIN 46R. In 1997, the Company and TE established Shippingport to purchase all of the lease obligation bonds issued by the owner trusts in the Bruce Mansfield Plant sale and leaseback transactions. Prior to the adoption of FIN 46R, the assets and liabilities of the trust were included on a proportionate basis in the financial statements of the Company and TE. Upon adoption of FIN 46R, the Company was determined to be the primary beneficiary of Shippingport, and therefore consolidated the entire trust as of December 31, 2003. As a result, Shippingport's note payable to TE of approximately $208 million ($9 million current) is recognized as long-term debt on the Consolidated Balances Sheets. In reviewing the sale and leaseback arrangements, the Company also evaluated its interest in the owner trusts that acquired interests in the Bruce Mansfield Plant. The Company was determined not to be the primary beneficiary of any of these owner trusts and was therefore not required to consolidate these entities. The leases are accounted for as operating leases in accordance with GAAP and their related obligations are disclosed in Note 2. As described in Note 3(F), the Company created a statutory business trust to issue trust preferred securities in the amount of $100 million. Application of the guidance in FIN 46R resulted in the holders of the preferred securities being considered the primary beneficiaries of these trusts. Therefore, the Company has deconsolidated the trust and recognized an equity investment in the trust of $3 million and subordinated debentures to the trust of $103 million as of December 31, 2003. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the beginning of the first interim period beginning after June 15, 2003 for all other financial instruments. Upon adoption of SFAS 150, effective July 1, 2003, the Company reclassified as debt the preferred stock subject to mandatory redemption with a carrying value of approximately $5 million as of December 31, 2003. Dividends on preferred stock subject to mandatory redemption on the Company's Consolidated Statements of Income, which were not included in net interest charges prior to the adoption of SFAS 150, are now included in net interest charges for the six months ended December 31, 2003. SFAS 143, "Accounting for Asset Retirement Obligations" In January 2003, the Company implemented SFAS 143 which provides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an asset retirement obligation in the period in which it is incurred. See Notes 1(F) and 1(M) for further discussions of SFAS 143. 38 EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments" In November 2003, the EITF reached consensus that certain quantitative and qualitative disclosures are required for debt and equity securities classified as available-for-sale or held-to-maturity. The guidance requires the disclosure of the aggregate amount of unrealized losses and the aggregate related fair value for investments with unrealized losses that have not been recognized as other-than-temporary impairments. The Company adopted the disclosure requirements of EITF Issue No. 03-1 as of December 31, 2003 (See Note 1(K)). 8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2003 and 2002.
March 31, June 30, September 30, December 31, Three Months Ended 2003 2003 2003 2003 (a) ------------------------------------------------------------------------------------------------------------------ (In millions) Operating Revenues.......................... $419.8 $412.1 $496.7 $392.2 Operating Expenses and Taxes................ 365.8 367.6 396.7 335.6 ------------------------------------------------------------------------------------------------------------------- Operating Income ........................... 54.0 44.5 100.0 56.6 Other Income................................ 4.7 4.7 6.5 81.9 Net Interest Charges........................ 43.5 39.9 38.6 33.9 ------------------------------------------------------------------------------------------------------------------- Income Before Cumulative Effect of Accounting Change........................ 15.2 9.3 67.9 104.6 Cumulative Effect of Accounting Change (Net of Income Taxes).................... 42.4 -- -- -- Net Income.................................. $ 57.6 $ 9.3 $ 67.9 $104.6 =================================================================================================================== Earnings Applicable to Common Stock $ 58.4 $ 7.5 $ 66.0 $100.0 =================================================================================================================== March 31, June 30, September 30, December 31, Three Months Ended 2002 2002 2002 2002 ------------------------------------------------------------------------------------------------------------------ (In millions) Operating Revenues.......................... $433.3 $462.9 $538.9 $408.6 Operating Expenses and Taxes................ 375.8 355.8 419.0 387.0 ------------------------------------------------------------------------------------------------------------------- Operating Income ........................... 57.5 107.1 119.9 21.6 Other Income................................ 5.2 3.4 5.6 1.8 Net Interest Charges........................ 47.8 46.8 47.3 43.3 Net Income (Loss)........................... $ 14.9 $ 63.7 $ 78.2 $(19.8) =================================================================================================================== Earnings (Loss) Applicable to Common Stock $ 8.3 $ 60.6 $ 75.1 $(22.8) =================================================================================================================== (a) Net income for the three months ended December 31, 2003, was increased by $3.2 million due to adjustments that were subsequently capitalized to construction projects in the fourth quarter. The adjustments included $0.3 million, $1.2 million and $1.7 million of costs charged to expense in the first, second and third quarters, respectively. Management concluded that the adjustments were not material to the consolidated financial statements for any quarter of 2003.
39 Report of Independent Auditors To the Stockholders and Board of Directors of The Cleveland Electric Illuminating Company: In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2003 and 2002 and the results of their operations and their cash flows for each of the three yeas in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. 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 of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 1(L) to the consolidated financial statements, the Company changed its method of accounting for goodwill as of January 1, 2002. As discussed in Note 1(F) to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003. As discussed in Note 7 to the consolidated financial statements, the Company changed its method of accounting for the consolidation of variable interest entities as of December 31, 2003. PricewaterhouseCoopers LLP Cleveland, Ohio February 25, 2004 40