EX-13 19 oe_ex13-1.txt EX 13-1 OE ANNUAL REPORT OHIO EDISON COMPANY 2003 ANNUAL REPORT TO STOCKHOLDERS Ohio Edison Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. Ohio Edison engages in the generation, distribution and sale of electric energy to communities in an area of 7,500 square miles in central and northeastern Ohio and, through its wholly owned Pennsylvania Power Company subsidiary, 1,500 square miles in western Pennsylvania. It also engages in the sale, purchase and interchange of electric energy with other electric companies. Contents Page -------- ---- Selected Financial Data............................................ 1 Management's Discussion and Analysis............................... 2-13 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 Reports of Independent Auditors.................................... 40-41
OHIO EDISON COMPANY SELECTED FINANCIAL DATA 2003 2002 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------- (In thousands) Operating Revenues.......................... $2,925,832 $2,948,675 $3,056,464 $2,726,708 $2,686,949 --------------------------------------------------------------- Operating Income............................ $ 335,727 $ 453,831 $ 466,819 $ 482,321 $ 473,042 --------------------------------------------------------------- Income Before Cumulative Effect of Accounting Change........................ $ 292,925 $ 356,159 $ 350,212 $ 336,456 $ 297,689 ----------- ---------------------------------------------------- Net Income.................................. $ 324,645 $ 356,159 $ 350,212 $ 336,456 $ 297,689 --------------------------------------------------------------- Earnings on Common Stock.................... $ 321,913 $ 349,649 $ 339,510 $ 325,332 $ 286,142 --------------------------------------------------------------- Total Assets................................ $7,316,930 $7,790,041 $7,915,953 $8,154,151 $8,700,746 --------------------------------------------------------------- Capitalization as of December 31: Common Stockholder's Equity.............. $2,582,970 $2,839,255 $2,671,001 $2,556,992 $2,624,460 Preferred Stock: Not Subject to Mandatory Redemption.... 100,070 100,070 200,070 200,070 200,070 Subject to Mandatory Redemption........ -- 13,500 134,250 135,000 140,000 Long-Term Debt........................... 1,179,789 1,219,347 1,614,996 2,000,622 2,175,812 --------------------------------------------------------------- Total Capitalization................... $3,862,829 $4,172,172 $4,620,317 $4,892,684 $5,140,342 --------------------------------------------------------------- Capitalization Ratios: Common Stockholder's Equity.............. 66.9% 68.1% 57.8% 52.3% 51.1% Preferred Stock: Not Subject to Mandatory Redemption.... 2.6 2.4 4.3 4.1 3.9 Subject to Mandatory Redemption........ -- 0.3 2.9 2.7 2.7 Long-Term Debt........................... 30.5 29.2 35.0 40.9 42.3 --------------------------------------------------------------- Total Capitalization................... 100.0% 100.0% 100.0% 100.0% 100.0% --------------------------------------------------------------- Distribution Kilowatt-Hour Deliveries (Millions): Residential.............................. 10,009 10,233 9,646 9,432 9,483 Commercial............................... 8,105 7,994 7,967 8,221 8,238 Industrial............................... 10,658 10,672 10,995 11,631 11,310 Other.................................... 160 154 152 151 151 --------------------------------------------------------------- Total.................................... 28,932 29,053 28,760 29,435 29,182 --------------------------------------------------------------- Customers Served: Residential.............................. 1,044,419 1,041,825 1,033,414 1,014,379 1,016,793 Commercial............................... 127,856 119,771 118,469 116,931 115,581 Industrial............................... 1,182 4,500 4,573 4,569 4,627 Other.................................... 1,752 1,756 1,664 1,606 1,539 --------------------------------------------------------------- Total.................................... 1,175,209 1,167,852 1,158,120 1,137,485 1,138,540 --------------------------------------------------------------- Number of Employees ........................ 1,521 1,569 1,618 1,647 2,734
1 OHIO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management. 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 operation of generating units, the 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 financial statements for the year ended December 31, 2002, to reflect a change in the method of amortizing the costs associated with the Ohio transition plan. Financial comparisons described below reflect the effect of these restatements on 2002 financial results. Results of Operations --------------------- Earnings on common stock in 2003 decreased to $321.9 million from $349.6 million in 2002 and $339.5 million in 2001. The earnings decrease in 2003 primarily resulted from increased nuclear outage related costs, increased amortization of the Ohio transition regulatory assets and reduced operating revenues. These items were partially offset by reduced nuclear fuel expenses as a result of the additional nuclear outages, reduced financing costs and an after tax credit of $31.7 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $292.9 million in 2003, compared to $356.2 million for 2002 and $350.2 million for 2001. Operating revenues decreased by $22.8 million or 0.7% in 2003 compared with 2002 due to cooler-than-normal temperatures in the second and third quarters of 2003 and increased sales by alternative suppliers. The lower revenues primarily resulted from reduced generation sales revenues, which included all retail customer categories - residential, commercial and industrial. Kilowatt-hour sales to retail customers declined by 8.1% in 2003 from the prior year, reducing generation sales revenue by $98.0 million. Electric generation services provided to retail customers by alternative suppliers as a percent of total kilowatt-hours delivered in the Company's franchise area increased 6.1 percentage points in 2003 from last year. Operating revenues decreased by $107.8 million or 3.5% 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 changes in wholesale revenues. Retail kilowatt-hour sales declined by 8.7% in 2002 from the prior year, with declines in all customer sectors (residential, commercial and industrial), resulting in a $73.1 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 increased to 20.9% in 2002 from 12.5% in 2001, while our share of electric generation sales in our franchise areas decreased by 8.4% compared to the prior year. Distribution revenues from electricity throughput increased by $35.3 million in 2003 for all retail customer classes compared with 2002, primarily due to higher unit prices partially offset by the effects of slightly lower distribution deliveries in 2003. Distribution deliveries increased 1.0% in 2002 compared with 2001, which increased revenues from electricity throughput by $18.5 million in 2002 from the prior year. The higher distribution deliveries resulted from additional residential demand due to warmer summer weather that was offset in part by the effect that continued sluggishness in the economy had on demand by commercial and industrial customers. Operating revenues were further reduced in 2003 as a result of the Ohio transition plan incentives provided to customers to promote customer shopping for alternative suppliers - $8.1 million of additional credits in 2003 compared to 2 $27.6 million of additional credits in 2002 from 2001. These reductions in revenues are deferred for future recovery under the Company's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers increased by $46.7 million in 2003 compared with 2002. This reflected the effect of higher unit prices, which was partially offset by lower kilowatt-hour sales to the wholesale market due to reduced nuclear generation available for sale to FirstEnergy Solutions (FES), an affiliated company. Sales revenues from wholesale customers decreased by $18.0 million in 2002 compared to 2001, due to a decline in market prices. Changes in electric generation sales and distribution deliveries in 2003 compared to 2002 are summarized in the following table: Changes in Kilowatt-Hour Sales 2003 2002 ---------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail............................... (8.1)% (8.7)% Wholesale............................ (10.5)% 10.6% -------------------------------------------------------------------- Total Electric Generation Sales........ (9.2)% (0.6)% =================================================================== Distribution Deliveries: Residential.......................... (2.2)% 6.1% Commercial........................... 1.4% 0.3% Industrial........................... (0.1)% (2.9)% --------------------------------------------------------------------- Total Distribution Deliveries.......... (0.4)% 1.0% ================================================================== Operating Expenses and Taxes Total operating expenses and taxes increased by $95.3 million in 2003 and decreased by $94.8 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..................... $(19.9) $ (109.6) Nuclear operating costs...................... 80.2 (28.9) Other operating costs........................ 1.3 51.3 -------------------------------------------------------------------- Total operation and maintenance expenses... 61.6 (87.2) Provision for depreciation and amortization.. 52.6 (39.4) General taxes................................ (6.9) 23.5 Income taxes................................. (12.0) 8.3 -------------------------------------------------------------------- Total operating expenses and taxes......... $ 95.3 $(94.8) ===================================================================== Lower fuel costs in 2003 compared to 2002 resulted from reduced nuclear generation - down 10.5%. In 2003, the kilowatt-hour purchase requirements were lower than in 2002 because of reduced electric generation sales - those cost reductions were partially offset by the effect of higher unit costs. Higher nuclear operating costs in 2003 were driven by three nuclear refueling outages in 2003 - Beaver Valley Unit 1 (100% interest), Beaver Valley Unit 2 (55.62% interest) and the Perry Plant (35.24% interest) in 2003 compared with one refueling outage at Beaver Valley Unit 2 in 2002. The Beaver Valley Unit 1 and Perry refueling outages earlier in 2003 included additional unplanned work, which extended the length of the outages and increased their cost. Charges for depreciation and amortization increased by $52.6 million in 2003 compared to 2002 primarily from increased amortization of the Ohio transition regulatory assets ($57.9 million) and reduced transition plan regulatory asset deferrals ($27.3 million) in 2003. Partially offsetting these increases were higher shopping incentive deferrals ($8.1 million) and lower charges resulting from the implementation of SFAS 143 ($18.5 million), "Accounting for Asset Retirement Obligations." In 2002, depreciation and amortization decreased by $39.4 million compared to 2001 primarily due to higher shopping incentive deferrals and tax-related deferrals under the Ohio transition plan. General taxes decreased by $6.9 million in 2003 from 2002 principally due to settled property tax claims partially offset by higher kilowatt-hour taxes in Ohio. In 2002, general taxes increased by $23.5 million in 2002 from 2001 principally due to additional property taxes and the absence in 2002 of a one-time benefit of $15 million resulting from the successful resolution of certain property tax issues in the prior year. 3 Other Income Other income increased by $25.1 million in 2003 from the prior year, primarily due to the absence in 2003 of adjustments recorded in 2002 related to low-income housing investments. Net Interest Charges Net interest charges continued to trend lower, decreasing by $29.7 million in 2003 and by $44.8 million in 2002. We continued to redeem and refinance outstanding debt and preferred stock during 2003 - net redemptions and refinancing activities totaled $245.1 million and $542.0 million, respectively, and will result in annualized savings of $20.2 million. Cumulative Effect of Accounting Change Results for 2003 include an after-tax credit to net income of $31.7 million recorded upon the adoption of SFAS 143 in January 2003. We identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $133.7 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $25.2 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 $54.1 million increase to income, or $31.7 million net of income taxes. Capital Resources and Liquidity ------------------------------- Our improving financial position reflects ongoing efforts to increase competitiveness and enhance shareholder value. We have continued to strengthen our financial position over the past five years by improving our fixed charge coverage ratios. Our mortgage indenture ratio, which is used to measure our ability to issue first mortgage bonds, increased from 6.21 in 1997 to 15.92 in 2003, which enhances our financial flexibility. Over the same period, our charter ratio, a measure of our ability to issue preferred stock, improved from 2.35 to 4.68 and our common stockholder's equity as a percentage of capitalization rose from approximately 48% at the end of 1997 to 66.9% at the end of 2003. Over the last five years, we have reduced the average cost of long-term debt from 7.77% in 1997 to 4.51% at the end of 2003. Changes in Cash Position As of December 31, 2003, we had $1.9 million of cash and cash equivalents, compared with $20.5 million as of December 31, 2002. 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 $1.1 billion in 2003 and 2002 and $0.7 billion in 2001. Cash flows provided from 2003, 2002 and 2001 operating activities are as follows: Operating Cash Flows 2003 2002 2001 ---------------------------------------------------------------------- (In millions) Cash earnings (1)................ $ 689 $ 713 $743 Working capital and other........ 423 344 (75) ----------------------------------------------------------------------- Total............................ $1,112 $1,057 $668 ====================================================================== (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities increased $55 million in 2003 compared to 2002 due to a $79 million reduction in working capital requirements partially offset by a $24 million decrease from cash earnings. The change in net use of working capital primarily represents increases in accounts payable partially offset by decreased accounts receivable and higher tax accruals in 2003. Cash Flows From Financing Activities In 2003 and 2002, the net cash used for financing activities of $981.8 million and $598.6 million, respectively, primarily reflects the redemptions of debt and the payment of common stock dividends to FirstEnergy. The following table provides details regarding new issues and redemptions during 2003 and 2002: 4 Securities Issued or Redeemed 2003 2002 ---------------------------------------------------------------------- (In millions) New Issues Pollution Control Notes............... $ -- $ 15 Unsecured Notes....................... 325 -- Long-Term Revolving Credit............ 40 -- ---------------------------------------------------------------------- $ 365 $ 15 Redemptions First Mortgage Bonds.................. $ 410 $280 Pollution Control Notes............... 30 15 Secured Notes......................... 62 127 Preferred Stock....................... 1 221 Other, principally redemption premiums 17 4 ---------------------------------------------------------------------- $ 520 $647 Short-term Borrowings, Net (use)/source of cash $(225) $162 ---------------------------------------------------------------------- We had approximately $368.4 million of cash and temporary investments and approximately $182.9 million of short-term indebtedness at the end of 2003. Available borrowing capability under bilateral bank facilities totaled $142 million as of December 31, 2003. The Company and its wholly owned utility subsidiary, Pennsylvania Power Company (Penn), referred to as "Companies" had the capability to issue $2.1 billion of additional first mortgage bonds on the basis of property additions and retired bonds, although unsecured senior note indentures entered into by the Company in 2003 limit its ability to issue secured debt, including FMBs, subject to certain exceptions. Based upon applicable earnings coverage tests the Companies could issue a total of $2.6 billion of preferred stock (assuming no additional debt was issued) as of the end of 2003. 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, as well as proceeds available from bank borrowings. Available bank borrowings include $1.75 billion from FirstEnergy's and the Company's revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, 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- Ohio Edison Senior secured BBB Baa1 BBB+ Senior unsecured BB+ Baa2 BBB Preferred stock BB Ba1 BBB- Penn Senior secured BBB- Baa1 BBB+ Senior unsecured (1) BB+ Baa2 BBB Preferred stock BB Ba1 BBB- ------------------------------------------------------------------------- (1) Penn's only senior unsecured debt obligations are pollution control revenue refunding bonds issued in the name of the Ohio Air Quality Development Authority to which this rating applies. On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch affirmed the Companies' ratings. 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." 5 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-". Except for OE's senior secured issue rating, which was left unchanged, all other subsidiary ratings were lowered one notch as well. The ratings were removed from CreditWatch with negative implications, where 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 Regulatory Matters), the pending final report on the August 14th blackout (see Power Outage), the outcome of the remedial phase of litigation relating to the Sammis plant (see Environmental Matters), and the extended Davis-Besse outage (the Companies have no ownership interest in Davis-Besse) and the related pending subpoena. 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. The ratings of OE and Penn were confirmed. Moody's said that the 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 flows used in investing activities totaled $148 million in 2003 and $443 million in 2002. These net cash flows used for investing resulted from property additions for both years and notes to associated companies for 2002, which were offset in part by a reduction of the PNBV Capital Trust investment. Expenditures for property additions primarily include expenditures supporting our distribution of electricity. 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. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. 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. Our capital spending for the period 2004-2006 is expected to be about $438 million (excluding nuclear fuel) of which approximately $174 million applies to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $82 million, of which approximately $48 million relates to 2004. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $85 million and $43 million, respectively, as the nuclear fuel is consumed. Contractual Obligations ----------------------- Our cash contractual obligations as of December 31, 2003 that we consider firm obligations are as follows:
2005- 2007- Contractual Obligations Total 2004 2006 2008 Thereafter ---------------------------------------------------------------------------------------------------------------- (In millions) Long-term debt................... $1,639 $123 $182 $185 $1,149 Short-term borrowings............ 183 183 -- -- -- Preferred stock (1).............. 14 1 2 11 -- Capital leases (2)............... 15 4 9 1 1 Operating leases (2)............. 1,237 79 163 184 811 Purchases (3).................... 289 47 82 63 97 -------------------------------------------------------------------------------------------------------------- Total....................... $3,377 $437 $438 $444 $2,058 -------------------------------------------------------------------------------------------------------------- (1) Subject to mandatory redemption. (2) Operating lease payments are net of capital trust receipts of $591.0 million (see Note 2). (3) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.
Off-Balance Sheet Arrangements ------------------------------ Obligations not included on our Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2, which are 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 $689 million as of December 31, 2003. 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 which 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............... $308 $186 $37 $39 $ 17 $654 $1,241 $1,303 Average interest rate...... 7.8% 7.9% 8.1% 8.3% 8.2% 7.4% 7.6% ____________________________________________________________________________________________________________________ Liabilities Long-term Debt and Other Long-Term Obligations: Fixed rate.................... $123 $137 $ 5 $ 6 $179 $468 $ 918 $ 956 Average interest rate ..... 7.5% 7.2% 7.9% 7.9% 4.1% 6.0% 6.1% Variable rate................. $ 40 $681 $ 721 $ 721 Average interest rate...... 2.2% 2.3% 2.3% Preferred Stock Subject to Mandatory Redemption....... $ 1 $ 1 $ 1 $11 $ 14 $ 14 Average dividend rate...... 7.6% 7.6% 7.6% 7.6% 7.6% Short-term Borrowings......... $183 $ 183 $ 183 Average interest rate...... 1.2% 1.2% -------------------------------------------------------------------------------------------------------------------
Equity Price Risk ----------------- Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $209 million and $148 million as of December 31, 2003 and 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $21 million reduction in fair value as of December 31, 2003 (see Note 1(L) - Cash and Financial Instruments). Outlook ------- Our industry continues to transition to a more competitive environment. In 2001, all our customers could 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. In Ohio and Pennsylvania, 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 Ohio- Beginning on January 1, 2001, Ohio customers were able to choose their electricity suppliers. Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of our Ohio 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 for OE customers), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC) for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of our regulatory assets are expected 7 to continue to be recovered under the provisions of our transition plan as discussed below. Our regulatory assets are as follows: Regulatory Assets as of December 31, --------------------------------------------------------- Company 2003 2002 --------------------------------------------------------- (In millions) Ohio Edison................ $1,450 $1,787 Penn....................... 28 151 -------------------------------------------------------- Consolidated Total...... $1,478 $1,938 ======================================================== As part of our Ohio transition plan, we are obligated to supply electricity to customers who do not choose an alternative supplier. The Company is also required to provide 560 megawatts (MW) of low cost supply to unaffiliated alternative suppliers who serve customers within its service area. Our competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. On October 21, 2003, FirstEnergy's Ohio 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 2006 to 2007; 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. Pennsylvania- In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed 8 Rulemaking Order has closed. We are currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. It is expected that these Orders will be finalized in March 2004. On January 16, 2004, the PPUC initiated a formal investigation of and Penn's levels of compliance with the Public Utility Code and the PPUC's regulations and orders with regard to reliable electric service. Hearings will be held in August in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order before December 16, 2004. We are unable to predict the outcome of the investigation or the impact of the PPUC Order. 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 Companies' 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. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against the Companies in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on the Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2003. 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. 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 per kilowatt-hour of electricity generated by the Companies are lower than many regional competitors due to our diversified generation sources which includes the low or non-CO2 emitting gas-fired and nuclear generators. 9 Power Outage On August 14, 2003, various states in the northeast United States and 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 up 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 ISO and PJM Interconnection) to provide effective diagnostic support. We believe 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. We remain 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 Federal Energy Regulatory Commission (FERC) ordered FirstEnergy to pay for an independent study of part of Ohio's power grid. The study has commenced and will 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, we do not know how the results of the study will impact FirstEnergy. 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 ---------------------------- Significant 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 and Pennsylvania, a significant amount of regulatory assets have been recorded - $1.5 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 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, 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 increased by $67 million. The corresponding adjustment related to this change decreased other comprehensive income and deferred income taxes and increased 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 $85 million, recording an increase of $5 million in an intangible asset and crediting OCI by $53 million (offsetting previously recorded deferred tax benefits by $37 million). The remaining balance in OCI of $62 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 $81 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(J)). 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:
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 the regulatory books of the Ohio electric utilities. These costs exceeded those deferred or capitalized on the Company's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred. We use an effective interest method for amortizing its 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 for each respective company. 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. Nuclear Decommissioning In accordance with SFAS 143, we recognize 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 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. Upon adoption of FIN 46R effective December 31, 2003, we consolidated the PNBV Capital Trust (PNBV) which was created in 1996 to refinance debt in connection with sale and leaseback transactions. Consolidation of PNBV changed the trust investment of $361 million to an investment in collateralized lease bonds of $372 million. The $11 million increase represents the minority interest in the total assets of the trust. In reviewing the sale and leaseback arrangements, the Company also evaluated its interest in the owner trusts that acquired interests in the Perry Plant and Beaver Valley Unit 2. 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. 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, 12 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 of consolidated subsidiaries subject to mandatory redemption with a carrying value of approximately $14 million as of December 31, 2003. Prior to the adoption of SFAS 150, subsidiary preferred dividends on our Consolidated Statements of Income were included in net interest charges. Therefore, the application of SFAS 150 did not require the reclassification of such preferred dividends to net interest charges. 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(I) 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 7(C)). 13
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------ (In thousands) OPERATING REVENUES (Note 1(K)).......................................... $2,925,832 $2,948,675 $3,056,464 ---------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel and purchased power (Note 1(K))................................. 966,892 986,737 1,096,317 Nuclear operating costs.............................................. 432,315 352,129 381,047 Other operating costs (Note 1(K)).................................... 365,720 364,436 313,177 ---------- ---------- ---------- Total operation and maintenance expenses........................... 1,764,927 1,703,302 1,790,541 Provision for depreciation and amortization.......................... 438,121 385,520 424,920 General taxes........................................................ 170,078 177,021 153,506 Income taxes......................................................... 216,979 229,001 220,678 ---------- ---------- ---------- Total operating expenses and taxes................................. 2,590,105 2,494,844 2,589,645 ---------- ---------- ---------- OPERATING INCOME........................................................ 335,727 453,831 466,819 OTHER INCOME (Note 1(K))................................................ 67,991 42,859 68,681 ---------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES...................................... 403,718 496,690 535,500 ---------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt........................................... 91,068 119,123 150,632 Allowance for borrowed funds used during construction and capitalized interest.............................. (6,075) (3,639) (2,602) Other interest expense............................................... 22,069 14,598 22,754 Subsidiaries' preferred stock dividend requirements.................. 3,731 10,449 14,504 ---------- ---------- ---------- Net interest charges............................................... 110,793 140,531 185,288 ---------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE.................... 292,925 356,159 350,212 Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 1(I))........................................... 31,720 -- -- ---------- ---------- ---------- NET INCOME.............................................................. 324,645 356,159 350,212 PREFERRED STOCK DIVIDEND REQUIREMENTS................................... 2,732 6,510 10,702 ---------- ---------- ---------- EARNINGS ON COMMON STOCK................................................ $ 321,913 $ 349,649 $ 339,510 ========== ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS As of December 31, 2003 2002 ------------------------------------------------------------------------------------------------------------------ (In thousands) ASSETS UTILITY PLANT: In service...................................................................... $5,269,042 $4,989,056 Less-Accumulated provision for depreciation..................................... 2,578,899 2,484,162 ---------- ---------- 2,690,143 2,504,894 ---------- ---------- Construction work in progress- Electric plant................................................................ 145,380 122,741 Nuclear Fuel.................................................................. 554 23,481 ---------- ---------- 145,934 146,222 ---------- ---------- 2,836,077 2,651,116 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Investments in lease obligation bonds (Note 2).................................. 383,510 402,565 Letter of credit collateralization (Note 2)..................................... 277,763 277,763 Nuclear plant decommissioning trusts............................................ 376,367 293,190 Long-term notes receivable from associated companies (Note 3(B)................. 508,594 503,827 Other........................................................................... 59,102 74,220 ---------- ---------- 1,605,336 1,551,565 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents....................................................... 1,883 20,512 Receivables- Customers (less accumulated provisions of $8,747,000 and $5,240,000, respectively, for uncollectible accounts)................................... 280,538 296,548 Associated companies.......................................................... 436,991 592,218 Other (less accumulated provision of $2,282,000 and $1,000,000 for uncollectible accounts)..................................................... 28,308 30,057 Notes receivable from associated companies...................................... 366,501 437,669 Materials and supplies, at average cost- Owned......................................................................... 79,813 58,022 Under consignment............................................................. -- 19,753 Prepayments and other........................................................... 14,390 11,804 ---------- ---------- 1,208,424 1,466,583 ---------- ---------- DEFERRED CHARGES: Regulatory assets............................................................... 1,477,969 1,937,709 Property taxes.................................................................. 59,279 59,035 Unamortized sale and leaseback costs............................................ 65,631 72,294 Other........................................................................... 64,214 51,739 ---------- ---------- 1,667,093 2,120,777 ---------- ---------- $7,316,930 $7,790,041 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity..................................................... $2,582,970 $2,839,255 Preferred stock not subject to mandatory redemption............................. 60,965 60,965 Preferred stock of consolidated subsidiary- Not subject to mandatory redemption........................................... 39,105 39,105 Subject to mandatory redemption (Note 3(F))................................... -- 13,500 Long-term debt and other long-term obligations - Preferred stock of consolidated subsidiary subject to mandatory redemption (Note 3(F)) ..................................................... 12,750 -- Other......................................................................... 1,167,039 1,219,347 ---------- ---------- 3,862,829 4,172,172 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock............................ 466,589 563,267 Short-term borrowings - Associated companies.......................................................... 11,334 225,345 Other......................................................................... 171,540 182,317 Accounts payable- Associated companies.......................................................... 271,262 145,981 Other......................................................................... 7,979 18,015 Accrued taxes................................................................... 560,345 466,064 Accrued interest................................................................ 18,714 28,209 Other........................................................................... 58,680 74,562 ---------- ---------- 1,566,443 1,703,760 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes............................................... 867,691 1,017,629 Accumulated deferred investment tax credits..................................... 75,820 88,449 Asset retirement obligation..................................................... 317,702 -- Nuclear plant decommissioning costs............................................. -- 280,858 Retirement benefits............................................................. 331,829 247,531 Other........................................................................... 294,616 279,642 ---------- ---------- 1,887,658 1,914,109 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 2 and 5)...................................... ---------- ---------- $7,316,930 $7,790,041 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
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OHIO EDISON 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 175,000,000 shares-100 shares outstanding ................................................................... $2,098,729 $2,098,729 Accumulated other comprehensive loss (Note 3(G))................................. (38,693) (59,495) Retained earnings (Note 3(A)).................................................... 522,934 800,021 ---------- ---------- Total common stockholder's equity............................................ 2,582,970 2,839,255 ---------- ---------- Number of Shares Optional Outstanding Redemption Price ---------------- -------------------- 2003 2002 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK (Note 3(D)): Cumulative, $100 par value- Authorized 6,000,000 shares Not Subject to Mandatory Redemption: 3.90%................................ 152,510 152,510 $103.63 $15,804 15,251 15,251 4.40%................................ 176,280 176,280 108.00 19,038 17,628 17,628 4.44%................................ 136,560 136,560 103.50 14,134 13,656 13,656 4.56%................................ 144,300 144,300 103.38 14,917 14,430 14,430 ------- ------- ------- ---------- ---------- Total Not Subject to Mandatory Redemption............. 609,650 609,650 $63,893 60,965 60,965 ======= ======= ======= ---------- ---------- PREFERRED STOCK OF CONSOLIDATED SUBSIDIARY (Note 3(D)): Pennsylvania Power Company- Cumulative, $100 par value- Authorized 1,200,000 shares Not Subject to Mandatory Redemption: 4.24%................................ 40,000 40,000 $103.13 $ 4,125 4,000 4,000 4.25%................................ 41,049 41,049 105.00 4,310 4,105 4,105 4.64%................................ 60,000 60,000 102.98 6,179 6,000 6,000 7.75%................................ 250,000 250,000 100.00 25,000 25,000 25,000 ------- ------- ------- ---------- ---------- Total Not Subject to Mandatory Redemption....................... 391,049 391,049 $39,614 39,105 39,105 ======= ======= ======= ---------- ---------- Subject to Mandatory Redemption (Note 3(F)): 7.625%**............................. -- 142,500 -- 14,250 Redemption Within One Year**......... (750) ------- ------- ---------- ---------- Total Subject to Mandatory Redemption -- 142,500 -- 13,500 ======= ======= ---------- ----------
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OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd) As of December 31, 2003 2002 2003 2002 2003 2002 ----------------------------------------------------------------------------------------------------------------- (In thousands) LONG-TERM DEBT (Note 3(E)): First mortgage bonds: Ohio Edison Company- Pennsylvania Power Company- 8.625% due 2003........ -- 150,000 9.740% due 2004-2019. 15,617 16,591 6.875% due 2005........ 80,000 80,000 7.500% due 2003...... -- 40,000 8.750% due 2022........ -- 50,960 6.375% due 2004...... 20,500 20,500 7.625% due 2023........ -- 75,000 6.625% due 2004...... 14,000 14,000 7.875% due 2023........ -- 93,500 8,500% due 2022...... 27,250 27,250 ------- ------- 7.625% due 2023...... 6,500 6,500 ------- ------- Total first mortgage bonds.. 80,000 449,460 83,867 124,841 163,867 574,301 ------- ------- ------- ------- ---------- ---------- Secured notes: Ohio Edison Company- Pennsylvania Power Company- 7.680% due 2005........ 109,081 162,504 5.400% due 2013...... 1,000 1,000 *1.050% due 2015........ 19,000 19,000 5.400% due 2017...... 10,600 10,600 6.750% due 2015........ 40,000 40,000 *1.100% due 2017...... 17,925 17,925 *3.250% due 2015........ 50,000 -- 5.900% due 2018...... 16,800 16,800 7.050% due 2020........ 60,000 60,000 *1.100% due 2021...... 14,482 14,482 *1.100% due 2021........ 443 443 6.150% due 2023...... 12,700 12,700 5.375% due 2028........ 13,522 13,522 *1.200% due 2027...... 10,300 10,300 5.625% due 2029........ 50,000 50,000 5.375% due 2028...... 1,734 1,734 5.950% due 2029........ 56,212 56,212 5.450% due 2028...... 6,950 6,950 *1.050% due 2030........ 60,400 60,400 6.000% due 2028...... 14,250 14,250 *1.100% due 2031........ 69,500 69,500 5.950% due 2029...... 238 238 ------- ------- *1.100% due 2033........ 57,100 57,100 5.450% due 2033........ 14,800 14,800 *2.250% due 2033........ 50,000 -- Limited Partnerships- 7.37% weighted average interest rate due 2004-2010. .......... 21,432 29,513 ------- ------- Total secured notes......... 671,490 632,994 106,979 106,979 778,469 739,973 ------- ------- ------- ------- ---------- ---------- Unsecured notes: Ohio Edison Company- Pennsylvania Power Company- *2.238% due 2005........ 40,000 -- *5.900% due 2033...... 5,200 5,200 4.000% due 2008........ 175,000 -- *2.500% due 2029...... 14,500 14,500 ------- ------- *1.120% due 2014........ 50,000 50,000 5.450% due 2015........ 150,000 -- 4.850% due 2015........ -- 50,000 *5.800% due 2016........ 47,725 47,725 *1.340% due 2018........ 33,000 33,000 *1.300% due 2018........ 23,000 23,000 *1.300% due 2023........ 50,000 50,000 4.300% due 2033........ -- 50,000 *4.650% due 2033........ 108,000 108,000 4.400% due 2033........ -- 30,000 ------- ------- Total unsecured notes....... 676,725 441,725 19,700 19,700 696,425 461,425 ------- ------- ------- ------- ---------- ---------- Preferred stock subject to mandatory redemption**............................................ 13,500 -- ---------- ---------- Capital lease obligations (Note 2)........................................................... 6,829 8,249 ---------- ---------- Net unamortized discount on debt............................................................. (12,712) (2,084) ---------- ---------- Long-term debt due within one year**......................................................... (466,589) (562,517) ---------- ---------- Total long-term debt and long-term obligations**............................................ 1,179,789 1,219,347 ---------- ---------- TOTAL CAPITALIZATION........................................................................ $3,862,829 $4,172,172 ========== ========== * Denotes variable rate issue with December 31, 2003 interest rate shown. ** The December 31, 2003 balance for preferred stock subject to mandatory redemption is classified as debt under SFAS 150 (see Note 6). The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
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OHIO EDISON 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....................... 100 $2,098,729 $ -- $458,263 Net income.................................. $350,212 350,212 ======== Cash dividends on preferred stock........... (10,703) Cash dividends on common stock.............. (225,500) ------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001..................... 100 2,098,729 -- 572,272 Net income.................................. $356,159 356,159 Minimum liability for unfunded retirement benefits, net of $(45,525,000) of income taxes ............................. (64,585) (64,585) Unrealized gain on investments, net of $3,582,000 of income taxes................ 5,090 5,090 -------- Comprehensive income........................ $296,664 ======== Cash dividends on preferred stock........... (6,510) Cash dividends on common stock.............. (121,900) ------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002..................... 100 2,098,729 (59,495) 800,021 Net income.................................. $324,645 324,645 Minimum liability for unfunded retirement benefits, net of $2,014,000 of income taxes ............................. 2,674 2,674 Unrealized gain on investments, net of $12,337,000 of income taxes............... 18,128 18,128 -------- Comprehensive income........................ $345,447 ======== Cash dividends on preferred stock........... (2,732) Cash dividends on common stock.............. (599,000) ------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2003..................... 100 $2,098,729 $(38,693) $522,934 ===================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemption -------------------- -------------------- Number Par Number Par of Shares Value of Shares Value --------- ----- --------- ----- (Dollars in thousands) Balance, January 1, 2001......... 5,000,699 $200,070 5,000,000 $ 140,000 Redemptions- 8.45% Series................ (50,000) (5,000) ------------------------------------------------------------------------------------ Balance, December 31, 2001....... 5,000,699 200,070 4,950,000 135,000 Redemptions - 7.75% Series................ (4,000,000) (100,000) 9.00% Series................ (4,800,000) (120,000) 7.625% Series................ (7,500) (750) ------------------------------------------------------------------------------------- Balance, December 31, 2002....... 1,000,699 100,070 142,500 14,250 Redemptions - 7.625% Series................ (7,500) (750) ------------------------------------------------------------------------------------- Balance, December 31, 2003....... 1,000,699 $100,070 135,000 $ 13,500* ===================================================================================== * December 31, 2003 balance for preferred stock subject to mandatory redemption is classified as debt under SFAS 150 (see Note 6). The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
18
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income............................................................... $ 324,645 $ 356,159 $ 350,212 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization......................... 438,121 385,520 424,920 Nuclear fuel and lease amortization................................. 39,317 47,597 45,417 Cumulative effect of accounting change.............................. (54,109) -- -- Deferred income taxes, net.......................................... (73,541) (61,987) (63,945) Investment tax credits, net......................................... (14,747) (13,732) (13,346) Receivables......................................................... 170,492 (41,584) (61,246) Materials and supplies.............................................. (2,038) (9,930) 64,177 Accounts payable.................................................... 132,983 182,229 (53,588) Other (Note 7)...................................................... 150,499 212,929 (24,912) ---------- ---------- --------- Net cash provided from operating activities....................... 1,111,622 1,057,201 667,689 ---------- ---------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt........................................................ 365,000 14,500 111,584 Short-term borrowings, net............................................ -- 161,836 -- Redemptions and Repayments- Preferred stock....................................................... (750) (220,750) (5,000) Long-term debt........................................................ (519,506) (425,742) (233,158) Short-term borrowings, net............................................ (224,788) -- (69,606) Dividend Payments- Common stock.......................................................... (599,000) (121,900) (225,500) Preferred stock....................................................... (2,732) (6,510) (10,703) ---------- ---------- --------- Net cash used for financing activities............................ (981,776) (598,566) (432,383) ---------- ---------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions....................................................... (189,019) (148,967) (145,427) Loan payments from (to) associated companies............................. 66,401 (327,876) (261,044) Sale of assets to associated companies................................... -- -- 154,596 Other (Note 7)........................................................... (25,857) 34,132 2,888 ---------- ---------- --------- Net cash used for investing activities............................ (148,475) (442,711) (248,987) ---------- ---------- --------- Net increase (decrease) in cash and cash equivalents..................... (18,629) 15,924 (13,681) Cash and cash equivalents at beginning of year........................... 20,512 4,588 18,269 ---------- ---------- --------- Cash and cash equivalents at end of year................................. $ 1,883 $ 20,512 $ 4,588 ========== ========== ========= SUPPLEMENTAL CASH FLOWS INFORMATION: Cash Paid During the Year- Interest (net of amounts capitalized)............................... $ 103,632 $ 118,535 $ 180,263 ========== ========== ========= Income taxes........................................................ $ 250,564 $ 126,558 $ 240,882 ========== ========== ========= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
19
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF TAXES For the Years Ended December 31, 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------ (In thousands) GENERAL TAXES: Real and personal property............................................. $ 51,074 $ 65,709 $ 45,132 State gross receipts*.................................................. 18,028 18,516 45,271 Ohio kilowatt-hour excise*............................................. 91,296 85,762 55,795 Social security and unemployment....................................... 6,992 5,438 4,159 Other.................................................................. 2,688 1,596 3,149 -------- ---------- ---------- Total general taxes............................................... $170,078 $ 177,021 $ 153,506 ======== ========== ========== PROVISION FOR INCOME TAXES: Currently payable- Federal............................................................. $270,345 $ 280,587 $ 265,305 State............................................................... 81,505 55,796 51,121 -------- ---------- ---------- 351,850 336,383 316,426 -------- ---------- ---------- Deferred, net- Federal............................................................. (57,503) (44,552) (56,105) State............................................................... (16,038) (22,184) (7,840) -------- ---------- ---------- (73,541) (66,736) (63,945) -------- ---------- ---------- Investment tax credit amortization..................................... (14,747) (13,732) (13,346) -------- ---------- ---------- Total provision for income taxes.................................. $263,562 $ 255,915 $ 239,135 ======== ========== ========== INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating income....................................................... $216,979 $ 229,001 $ 220,678 Other income........................................................... 24,194 26,914 18,457 Cumulative effect of accounting change................................. 22,389 -- -- -------- ---------- ---------- Total provision for income taxes.................................. $263,562 $ 255,915 $ 239,135 ======== ========== ========== RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes.......................... $588,207 $ 612,074 $ 589,347 ======== ========== ========== Federal income tax expense at statutory rate........................... $205,872 $ 214,225 $ 206,271 Increases (reductions) in taxes resulting from- Amortization of investment tax credits.............................. (14,747) (13,732) (13,346) State income taxes, net of federal income tax benefit............... 42,554 21,848 28,133 Amortization of tax regulatory assets............................... 33,219 30,659 32,020 Other, net.......................................................... (3,336) 2,915 (13,943) -------- ---------- ---------- Total provision for income taxes.................................. $263,562 $ 255,915 $ 239,135 ======== ========== ========== ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences............................................. $406,783 $ 397,930 $ 374,138 Allowance for equity funds used during construction.................... 30,493 34,407 36,587 Regulatory transition charge........................................... 345,723 527,502 675,652 Customer receivables for future income taxes........................... 44,382 49,486 54,600 Deferred sale and leaseback costs...................................... (67,837) (71,830) (77,099) Unamortized investment tax credits..................................... (29,031) (33,421) (38,680) Deferred gain for asset sale to affiliated company..................... 53,010 70,812 85,311 Other comprehensive income............................................. (27,219) (41,570) -- Other (Note 7)......................................................... 111,387 84,313 64,886 -------- ---------- ---------- Net deferred income tax liability................................. $867,691 $1,017,629 $1,175,395 ======== ========== ========== * Collected from customers through regulated rates and included in revenue on 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 Ohio Edison Company (Company) and its wholly owned subsidiaries. Pennsylvania Power Company (Penn) is the Company's principal operating subsidiary. 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 The Cleveland Electric Illuminating Company (CEI), 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 and Penn (Companies) follow the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The Company's consolidated financial statements for the year ended December 31, 2002 were restated to reflect a change in the method of amortizing costs being recovered under the Ohio transition plan. 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 Companies' principal business is providing electric service to customers in central and northeastern Ohio and western Pennsylvania. The Companies' 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 Companies' 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 Companies' customers. Total customer receivables were $281 million (billed - $165 million and unbilled - $116 million) and $297 million (billed - $169 million and unbilled - $128 million) as of December 31, 2003 and 2002, respectively. (C) REGULATORY MATTERS- Ohio- 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, CEI and TE (Ohio Companies) as modified by a settlement agreement with major parties to the transition plan. The application of Statement of Financial Accounting Standards No. (SFAS) 71 , "Accounting for the Effects of Certain Types of Regulation" to the Company's 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 the Company's 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 $1.0 billion net of deferred income taxes, with recovery through no later than 2006 for the Company except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.0 billion, net of deferred income taxes, of impaired generating assets recognized as regulatory assets as described further below and $1.2 billion, net of deferred income taxes, of above market operating lease costs. 21 Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 560 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 $41 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 FirstEnergy'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, OE is requesting: o Extension of the transition cost amortization period from 2006 to 2007; 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. 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. Pennsylvania- Pennsylvania enacted its electric utility competition law in 1996 with the phase-in of customer choice for generation suppliers completed as of January 1, 2001. In 1998, the PPUC authorized a rate restructuring plan for Penn, which essentially resulted in the deregulation of Penn's generation business. In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the 22 Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. Penn is currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. It is expected that these Orders will be finalized in March 2004. On January 16, 2004, the PPUC initiated a formal investigation of Penn's levels of compliance with the Public Utility Code and the PPUC's regulations and orders with regard to reliable electric service. The investigation is to determine whether Penn's reliability performance has deteriorated to a point below the level of service reliability that existed prior to the implementation of electric restructuring in Pennsylvania. Hearings will be held in August in this investigation and the Administrative Law Judge has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order before December 16, 2004. Penn is unable to predict the outcome of the investigation or the impact of the PPUC Order. Transition Cost Amortization - The Company amortizes transition costs (see Regulatory Matters - Ohio) using the effective interest method. Under the current Ohio transition plan, total transition cost amortization is expected to approximate the following for 2004 through 2006. (In millions) --------------------------------- 2004.................. $471 2005.................. 553 2006.................. 146 --------------------------------- The decrease in amortization in 2006 results from the termination of generation-related transition cost recovery under the Ohio transition plan. Regulatory Assets- The Companies recognize, as regulatory assets, costs which the FERC, PUCO and PPUC have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Companies' respective transition and rate restructuring plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2003 2002 ------------------------------------------------------------------------------ (In millions) Regulatory transition charge...................... $1,331 $1,761 Customer shopping incentives...................... 140 79 Customer receivables for future income taxes...... 115 127 Loss on reacquired debt........................... 29 28 Employee postretirement benefit costs............. 6 9 Nuclear decommissioning costs..................... (72) -- Component removal costs (Note 1(F))............... (72) (67) Other............................................. 1 1 ------------------------------------------------------------------------------ Total........................................... $1,478 $1,938 ============================================================================== Regulatory Accounting for Generation Operations- The application of SFAS 71 was discontinued with respect to the Companies' generation operations. The SEC issued interpretive guidance regarding asset impairment measurement providing that any supplemental regulated cash flows such as a competitive transition charge (CTC) should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance, $1.2 billion of impaired plant investments were recognized by the Company as regulatory assets recoverable as transition costs through future regulatory cash flows and $227 million were recognized for Penn related to its 1998 impairment of its nuclear generating unit investments to be recovered through a CTC over a seven-year transition period. 23 Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued, compared to the respective company's total assets as of December 31, 2003 were $976 million and $6.59 billion, respectively, for the Company and $92 million and $921 million, respectively, for Penn. (D) UTILITY PLANT AND DEPRECIATION- Utility plant reflects the original cost of construction (except for the Companies' nuclear generating units which were adjusted to fair value) including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The Companies' accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for the Company's electric plant was approximately 2.8% in 2003 and 2.7% in 2002 and 2001. The annual composite rate for Penn's electric plant was approximately 2.6% in 2003 and 2.9% in 2002 and 2001. Nuclear Fuel - Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Companies amortize the cost of nuclear fuel based on the rate of consumption. (E) COMMON OWNERSHIP OF GENERATING FACILITIES- The Companies, together with CEI and TE, 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 Companies' portions of operating expenses associated with jointly owned facilities are 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:
Companies' Utility Accumulated Construction Ownership/ Plant Provision for Work in Leasehold Generating Units in Service Depreciation Progress Interest ------------------------------------------------------------------------------------------------------------- (In millions) W. H. Sammis #7.................. $ 335 $ 165 $ -- 68.80% Bruce Mansfield #1, #2 and #3.... 991 529 -- 67.18% Beaver Valley #1 and #2.......... 192 35 110 77.81% Perry............................ 357 352 8 35.24% ------------------------------------------------------------------------------------------------------------- Total....................... $1,875 $1,081 $118 =============================================================================================================
(F) ASSET RETIREMENT OBLIGATION- In January 2003, the Companies 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 Companies identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond related to the Bruce Mansfield Plant. The ARO liability as of the date of adoption of SFAS 143 was $297.6 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. Accretion during 2003 was $20.1 million, bringing the ARO liability as of December 31, 2003 to $317.7 million. The ARO includes the Companies' obligation for nuclear decommissioning of the Beaver Valley and Perry generating facilities. The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. The Companies 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 Companies maintain 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 $376.4 million. In accordance with SFAS 143, the Companies ceased the accounting practice of depreciating non-regulated generation assets using a cost of removal component in the depreciation rates. That practice recognized accumulated 24 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 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.................................... $356 $350 Increase (Decrease): Elimination of decommissioning expense................. 30 30 Depreciation of asset retirement cost.................. (1) (1) Accretion of ARO liability............................. (11) (10) Non-regulated generation cost of removal component, net 5 4 Income tax effect...................................... (9) (9) ------------------------------------------------------------------------------- Net earnings increase.................................. 14 14 ------------------------------------------------------------------------------ Net income adjusted.................................... $370 $364 ============================================================================== 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 $278.8 Accretion in 2002 18.8 -------------------------------------------------------- Ending balance as of December 31, 2002 $297.6 -------------------------------------------------------- (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 3(C)). 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% 5.00% Risk-free interest rate...... 3.67% 4.60% 4.67% Fair value per option.......... $5.09 $6.45 $4.97 ----------------------------------------------------------------- The effects of applying fair value accounting to the Companies' stock options would not materially affect 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 Companies are included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Companies recognizing any tax losses or credits they contribute to the consolidated +return. 25 (I) CUMULATIVE EFFECT OF ACCOUNTING CHANGE- Results for 2003 include an after-tax credit to net income of $31.7 million recorded upon the adoption of SFAS 143 in January 2003. The Companies identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $133.7 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $25.2 million. The ARO liability at the date of adoption was $297.6 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 Companies had recorded decommissioning liabilities of $281 million. Penn expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, Penn recognized a regulatory liability of $69 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning. The remaining 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, resulted in a $54.1 million increase to income, or $31.7 million net of income taxes. (J) PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of the Companies' 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 Companies recognize the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. 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 in the FirstEnergy's Consolidated Balance Sheets as of December 31: 26
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) ====== ====== ===== ===== Companies' share of net amount recognized............................. $ 53 $ 57 $(249) $(171) ====== ====== ===== ===== Increase (decrease) 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: 27
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 ===== ===== ===== ==== ==== ==== Companies' share of net benefit costs... $ 24 $ 3 $ (3) $ 43 $ 15 $ 16 ===== ===== ===== ==== ==== ==== 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. 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 Companies as of June 30, 2003 increased by $67 million. The corresponding adjustment related to this change decreased other comprehensive income and deferred income taxes and increased the payable to associated companies. Due to the increased market value of their pension plan assets, the Companies reduced their minimum liability as prescribed by SFAS 87 as of December 31, 2003 by $85 million, recording an increase of $5 million in an intangible asset and crediting OCI by $53 million (offsetting previously recorded deferred tax benefits by $37 million). The remaining balance in OCI of $62 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 $81 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. 28 (K) 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 Companies, CEI and TE. As a result, the Companies entered into power supply agreements (PSA) whereby FES purchases all of the Companies' nuclear generation and the Companies purchase their power from FES to meet their "provider of last resort" obligations. The primary affiliated companies transactions are as follows: 2003 2002 2001 ----------------------------------------------------------------------------- (In millions) Operating Revenues: PSA revenues from FES................ $384 $329 $ 356 Generating units rent from FES....... 178 178 179 Ground lease with ATSI............... 12 12 12 Operating Expenses: Purchased power under PSA............ 902 912 1,026 Transmission expense................. 65 85 61 FESC support services................ 116 141 147 Other Income: Interest income from ATSI............ 16 16 16 Interest income from FES............. 12 12 12 ------------------------------------------------------------------------------ FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Companies 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. (L) 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. 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................................. $1,639 $1,677 $1,776 $1,861 Preferred stock*............................... $ 14 $ 14 $ 14 $ 14 Investments other than cash and cash equivalents: Debt securities: - Maturity (5-10 years)..................... $ 550 $ 534 $ 570 $ 539 - Maturity (more than 10 years)............. 469 548 458 532 Equity securities........................... -- -- 12 12 All other................................... 430 430 361 361 ---------------------------------------------------------------------------------------------------- $1,449 $1,512 $1,401 $1,444 ==================================================================================================== * 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 29 of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Companies' ratings. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. The Companies have no securities held for trading purposes. See Note 7 for discussion of SFAS 115 activity related to available-for-sale securities. 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 ($209 million) and fixed income securities ($167 million) as of December 31, 2003. In 2001, unrealized gains and losses applicable to the decommissioning trusts were recognized in the trust investment with a corresponding change to the decommissioning liability. In 2003 and 2002, unrealized gains and losses applicable to the Company's decommissioning trusts were offset to OCI in accordance with SFAS 115, 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 gains (losses) were approximately $5.1 million and $(3.4) million, respectively, and interest and dividend income totaled approximately $10.0 million and $8.9 million, respectively. 2. LEASES The Companies lease certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. The Company sold portions of its ownership interest in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. During the terms of the leases, the Company continues to be responsible, to the extent of its individual combined ownership and leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company has the right, at the end of the respective basic lease terms, to renew the leases for up to two years. The Company also has the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes. OES Finance, Incorporated, a wholly owned subsidiary of the Company, maintains deposits pledged as collateral to secure reimbursement obligations relating to certain letters of credit supporting the Company's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits of approximately $278 million pledged to the financial institution providing those letters of credit are the sole property of OES Finance and are investments which are classified as "Held to Maturity." In the event of liquidation, OES Finance, as a separate corporate entity, would have to satisfy its obligations to creditors before any of its assets could be made available to the Company as sole owner of OES Finance common stock. Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2003, are summarized as follows: 2003 2002 2001 ------------------------------------------------------------------ (In millions) Operating leases Interest element......... $ 96.4 $100.9 $102.7 Other.................... 41.2 34.6 31.6 Capital leases Interest element......... 1.7 1.6 1.9 Other.................... 1.4 1.3 1.9 ------------------------------------------------------------------ Total rentals............ $140.7 $138.4 $138.1 ================================================================== 30
The future minimum lease payments as of December 31, 2003, are: Operating Leases ----------------------------------- Capital Lease PNBV Capital Leases Payments Trust Net --------------------------------------------------------------------------------------------- (In millions) 2004...................................... $ 4.3 $ 137.8 $ 58.5 $ 79.3 2005...................................... 4.3 138.8 56.6 82.2 2006...................................... 4.3 139.9 59.5 80.4 2007...................................... 0.3 139.3 59.9 79.4 2008...................................... 0.3 139.6 34.9 104.7 Years thereafter.......................... 1.5 1,133.0 321.6 811.4 --------------------------------------------------------------------------------------------- Total minimum lease payments.............. 15.0 $1,828.4 $591.0 $1,237.4 ======== ====== ======== Executory costs........................... 5.3 ------------------------------------------------- Net minimum lease payments................ 9.7 Interest portion.......................... 2.9 ------------------------------------------------- Present value of net minimum lease payments.......................... 6.8 Less current portion...................... 1.5 ------------------------------------------------- Noncurrent portion........................ $ 5.3 =================================================
The Company invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in the Company's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. The PNBV capital trust arrangement effectively reduces lease costs related to those transactions. 3. CAPITALIZATION: (A) RETAINED EARNINGS- Under the Company's first mortgage indenture, the Company's consolidated retained earnings unrestricted for payment of cash dividends on the Company's common stock were $519.0 million as of December 31, 2003. (B) EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)- An ESOP Trust funds most of the matching contribution for FirstEnergy's 401(k) savings plan. All of the Companies' full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from the Company and acquired 10,654,114 shares of the Company's common stock (subsequently converted to FirstEnergy common stock) through market purchases. The ESOP loan is included in Other Property and Investments on the Consolidated Balance Sheets as of December 31, 2003 and 2002 as an investment with FirstEnergy related to the FirstEnergy savings plan. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. As of December 31, 2003, the Company had approximately $49 million receivable from FirstEnergy representing reductions to the outstanding loan balance from the ESOP Trust that were paid to FirstEnergy since 1998 that were intended to be remitted to the Company; that receivable will be paid in March 2004. (C) 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: 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 31 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 1(G) - "Stock-Based Compensation." (D) PREFERRED AND PREFERENCE STOCK- All preferred stock may be redeemed by the Companies in whole, or in part, with 30-60 days' notice. The Company has eight million authorized and unissued shares of preference stock having no par value. (E) LONG-TERM DEBT- Each of the Companies 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 also has a 1998 general mortgage under which it issues mortgage bonds based upon the pledge of a like amount of first mortgage bonds as security. These mortgage bonds therefore effectively enjoy the same lien on that 32 property. The Companies have various debt covenants under their respective financing arrangements. The most restrictive of their 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. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Companies. Based on the amount of bonds authenticated by the respective mortgage bond trustees through December 31, 2003, the Companies' annual sinking fund requirements for all bonds issued under the various mortgage indentures of the Companies amounts to $39 million. The Companies expect to deposit funds with their respective mortgage bond trustees in 2004 that will then be withdrawn upon the surrender for cancellation of a like principal amount of bonds, specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) --------------------------------------------- 2004............................... $464 2005............................... 227 2006............................... 5 2007............................... 6 2008............................... 229 ------------------------------------------ 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. These amounts are $341.7 million, $50 million and $50 million in 2004, 2005 and 2008, respectively, which represents the next date at which the debt holders may exercise this provision. The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $171.5 million and noncancelable municipal bond insurance policies of $288.9 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letters of credit or policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.375% to 1.50% of the amounts of the letters of credit to the issuing banks and are obligated to reimburse the banks for any drawings thereunder. The Company had unsecured borrowings of $40 million as of December 31, 2003 under a $250 million long-term revolving credit facility agreement which expires May 12, 2005. The Company currently pays an annual facility fee of 0.20% on the total credit facility amount. The Company had no unsecured borrowings as of December 31, 2003 under a $125 million long-term revolving credit facility which expires October 23, 2006. The Company currently pays an annual facility fee of 0.25% on the total credit facility amount. The fees are subject to change based on changes to the Company's credit ratings. (F) LONG-TERM DEBT: PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- Effective July 1, 2003, upon adoption of SFAS 150 (see Note 6), the Companies reclassified as debt Penn's preferred stock subject to mandatory redemption. Prior year amounts were not reclassified. Penn's 7.625% series has an annual sinking fund requirement for 7,500 shares. The Companies' preferred shares are retired at $100 per share plus accrued dividends. Annual sinking fund requirements are approximately $750,000 in each year 2004 through 2006 and $11.25 million in 2007. (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 $(61.9) million and unrealized gains on investments in securities available for sale of $23.2 million. 4. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT: Short-term borrowings outstanding as of December 31, 2003, consisted of $21.9 million of bank borrowings and $149.7 million of OES Capital, Incorporated commercial paper. OES Capital is a wholly owned subsidiary of the 33 Company whose borrowings are secured by customer accounts receivable. OES Capital can borrow up to $170 million under a receivables financing agreement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.50% on the amount of the entire finance limit. The receivables financing agreement expires in October 2004. As of December 31, 2003, the Company also had total short-term borrowings of $11.3 million from its affiliates. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2003 and 2002, were 1.16% and 1.63%, respectively. The Company has lines of credit with domestic banks that provide for borrowings of up to $159 million under various interest rate options. Short-term borrowings may be made under these lines of credit on its unsecured notes. To assure the availability of these lines, the Company is required to pay annual commitment fees of 0.20%. These lines expire at various times during 2004. 5. COMMITMENTS AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Companies' current forecast reflects expenditures of approximately $438 million for property additions and improvements from 2004-2006, of which approximately $174 million is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $82 million, of which approximately $48 million applies to 2004. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $85 million and $43 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 their ownership and leasehold interests in the Beaver Valley Station and the Perry Plant, the Companies' maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $192.0 million per incident but not more than $19.1 million in any one year for each incident. The Companies are also insured as to their respective interests in Beaver Valley and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Companies have also obtained approximately $537 million of insurance coverage for replacement power costs for their respective interests in Beaver Valley and Perry. Under these policies, the Companies can be assessed a maximum of approximately $29.1 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Companies intend to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies' plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs. (C) ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on the Companies' earnings and competitive position. These environmental regulations affect the Companies' earnings and competitive position to the extent that they compete 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 Companies believe they are 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 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 Companies are required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 34 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies are 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 Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of 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 Companies' Pennsylvania facilities by May 1, 2003. The Companies' Pennsylvania facilities complied with the NOx budgets in 2003 and all facilities will comply with the NOx budgets in 2004 and thereafter. Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. 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 Companies operate 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. W. H. Sammis Plant In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against the Companies in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on the Companies' financial condition 35 and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2003. 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. 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 Companies 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 Companies is lower than many regional competitors due to the Companies' 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 Companies' plants. In addition, Ohio and Pennsylvania have water quality standards applicable to the Companies' 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- Various lawsuits, claims and proceedings related to the Companies' normal business operations are pending against FirstEnergy and its subsidiaries. On August 14, 2003, eight 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 falls far short of providing 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. 36 6. 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 Companies adopted FIN 46R for interests in VIEs or potential VIEs commonly referred to as special-purpose entities effective December 31, 2003. The Companies 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. Upon adoption of FIN 46R effective December 31, 2003, the Company consolidated the PNBV Capital Trust (PNBV) which was created in 1996 to refinance debt in connection with sale and leaseback transactions. Consolidation of PNBV changed the trust investment of $361 million to an investment in collateralized lease bonds of $372 million. The $11 million increase represents the minority interest in the total assets of the trust. In reviewing the sale and leaseback arrangements, the Company also evaluated its interest in the owner trusts that acquired interests in the Perry Plant and Beaver Valley Unit 2. 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. 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 of consolidated subsidiaries subject to mandatory redemption with a carrying value of approximately $14 million as of December 31, 2003. Prior to the adoption of SFAS 150, subsidiary preferred dividends on the Company's Consolidated Statements of Income were included in net interest charges. Therefore, the application of SFAS 150 did not require the reclassification of such preferred dividends to net interest charges. SFAS 143, "Accounting for Asset Retirement Obligations" In January 2003, the Companies 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(I) 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. The Company has adopted the disclosure requirements of EITF Issue No. 03-1 as of December 31, 2003 (See Note 7(C)). 7. OTHER INFORMATION: The following financial data provides supplemental unaudited information to the consolidated financial statements previously reported in 2001: 37 (A) Consolidated Statements of Cash Flows (Unaudited) 2003 2002 2001 ---- ---- ---- (In thousands) Other Cash Flows From Operating Activities: Accrued taxes........................... $ 94,281 $208,945 $ 26,606 Accrued interest........................ (9,495) (4,844) (1,053) Prepayments and other................... (2,586) 38,737 26,393 All other............................... 68,299 (29,909) (76,858) ----------------------------------------------------------------------------- Total-Other........................... $150,499 $212,929 $(24,912) ============================================================================== Other Cash Flows from Investing Activities: Asset retirements and transfers......... $ 2,095 $ 7,476 $ 15,528 Nuclear decommissioning trust investments........................... (83,178) (15,688) (15,816) Other investments....................... 55,127 18,820 3,209 All other............................... 99 23,524 (33) ----------------------------------------------------------------------------- Total-Other........................... $(25,857) $ 34,132 $ 2,888 ============================================================================== (B) Consolidated Statements of Taxes (Unaudited) 2003 2002 2001 ---- ---- ---- (In thousands) Other Accumulated Deferred Income Taxes at December 31: Retirement Benefits..................... $(29,676) $ 20,969 $ 24,591 All other............................... 141,063 63,344 40,295 ------------------------------------------------------------------------------ Total-Other........................... $111,387 $ 84,313 $ 64,886 ============================================================================== (C) SFAS 115 Activity Investments other than cash and cash equivalents in the table in Note 1(L) - Cash and Financial Instruments include available-for-sale securities, at fair value, with the following net results: 2003* 2002* --------------------------------------------------------------- (In millions) Unrealized gains (losses)........... $ 30.7 $(17.5) Proceeds from sales................. 142.3 71.5 Realized gains (losses)............. 3.9 (3.1) --------------------------------------------------------------- * Includes the available-for-sale securities of the Companies' 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 $48.1 million and net unrealized losses of $6.8 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....... 3.7 1.1 21.0 5.6 24.7 6.7 Debt Securities......... 15.1 0.1 0.1 -- 15.2 0.1 ----------------------------------------------------------------------------------------------------- Total............... 18.8 1.2 21.1 5.6 39.9 6.8 -------------------------------------------------------------------------------------------------------
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. 38 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 30, Three Months Ended 2003 2003 2003 2003(a) ------------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues............................... $742.8 $673.7 $774.9 $734.4 Operating Expenses and Taxes..................... 672.7 609.7 686.9 620.8 ------------------------------------------------------------------------------------------------------------------- Operating Income................................. 70.1 64.0 88.0 113.6 Other Income..................................... 13.5 15.4 16.5 22.6 Net Interest Charges............................. 26.5 34.1 23.6 26.6 ------------------------------------------------------------------------------------------------------------------- Income Before Cumulative Effect of Accounting Change........................................ 57.1 45.3 80.9 109.6 Cumulative Effect of Accounting Change (Net of Income Taxes)................................. 31.7 -- -- -- Net Income....................................... $ 88.8 $ 45.3 $ 80.9 $109.6 =================================================================================================================== Earnings on Common Stock......................... $ 88.1 $ 44.7 $ 80.1 $109.0 =================================================================================================================== March 31, June 30, September 30, December 31, Three Months Ended 2002 2002 2002 2002 ------------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues............................... $707.8 $744.5 $813.3 $683.1 Operating Expenses and Taxes..................... 600.4 611.1 664.5 618.8 ------------------------------------------------------------------------------------------------------------------- Operating Income................................. 107.4 133.4 148.8 64.3 Other Income..................................... 0.5 15.1 14.2 13.0 Net Interest Charges............................. 41.2 35.9 33.7 29.8 ------------------------------------------------------------------------------------------------------------------- Net Income....................................... $ 66.7 $112.6 $129.3 $ 47.5 =================================================================================================================== Earnings on Common Stock......................... $ 64.0 $110.1 $128.6 $ 46.9 =================================================================================================================== (a) Net income for the three months ended December 31, 2003, was increased by $3.5 million due to adjustments that were subsequently capitalized to construction projects in the fourth quarter. The adjustments included $0.6 million, $1.0 million and $1.9 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 Ohio Edison 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 Ohio Edison 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 the years then ended 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. The consolidated financial statements of Ohio Edison Company and subsidiaries for the year ended December 31, 2001, prior to the revision described in Note 1(F), were audited by other independent auditors who have ceased operations. Those independent auditors expressed an unqualified opinion on those financial statements in their report dated March 18, 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 6 to the consolidated financial statements, the Company changed its method of accounting for the consolidation of variable interest entities as of December 31, 2003. As discussed above, the consolidated financial statements of Ohio Edison Company and subsidiaries for the year ended December 31, 2001 were audited by other independent auditors who have ceased operations. As described in Note 1(F) to the consolidated financial statements, the financial statements have been revised to include the transitional disclosures required by Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, which was adopted by the Company as of January 1, 2003. We audited the transitional disclosures described in Note 1(F). In our opinion, the transitional disclosures for 2001 are appropriate. However, we were not engaged to audit, review, or apply any procedures to the 2001 consolidated financial statements of the Company other than with respect to such transitional disclosures and, accordingly, we do not express an opinion or any other form of assurance on the 2001 consolidated financial statements taken as a whole. PricewaterhouseCoopers LLP Cleveland, Ohio February 25, 2004 40 The following report is a copy of a report previously issued by Arthur Andersen LLP (Andersen). This report has not been reissued by Andersen and Andersen did not consent to the incorporation by reference of this report into any of the Company's registration statements. As discussed in Note 1(F) to the consolidated financial statements, the Company has revised its consolidated financial statements for the year ended December 31, 2001 to include the transitional disclosures required by Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." The Andersen report does not extend to these changes. The revisions to the 2001 financial statements related to these transitional disclosures were reported on by PricewaterhouseCoopers LLP, as stated in their report appearing herein. Report of Independent Public Accountants To the Stockholders and Board of Directors of Ohio Edison Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Ohio Edison Company (an Ohio corporation and wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Ohio Edison Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. 41