10-K/A 1 fe_10k-a.txt AMENDMENT NO. 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K/A AMENDMENT No. 1 (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ----------------- ----------------- Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. ----------- ----------------------------------- ------------------ 333-21011 FIRSTENERGY CORP. 34-1843785 (An Ohio Corporation) 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 AMENDMENT NO. 1 EXPLANATORY NOTE As described in Note 2(L) to the consolidated financial statements, FirstEnergy Corp. has revised certain classifications in its previously reported Consolidated Statement of Income for the year ended December 31, 2002. The revisions had no effect on previously reported net income or earning per share. The following items have been amended: PART I ITEM 1. BUSINESS PART II ITEM 6. SELECTED FINANCIAL DATA ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA PART III ITEM 14. CONTROLS AND PROCEDURES PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of Each Exchange Registrant Title of Each Class on Which Registered ---------------- ----------------------------- ------------------------- FirstEnergy Corp. Common Stock, $0.10 par value New York Stock Exchange SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes (X) No ( ) - - Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X) Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act): Yes (X) No ( ) - - State the aggregate market value of the common stock held by non-affiliates of the registrant: FirstEnergy Corp., $9,920,663,231 as of June 28, 2002. Indicate the number of shares outstanding of the registrant's classes of common stock, as of the latest practicable date: OUTSTANDING CLASS AS OF MARCH 24, 2003 ----- -------------------- FirstEnergy Corp., $0.10 par value 297,636,276 Documents incorporated by reference (to the extent indicated herein): PART OF FORM 10-K INTO WHICH DOCUMENT DOCUMENT IS INCORPORTED -------- ---------------------------- FirstEnergy Corp. Annual Report to Stockholders for the fiscal year ended December 31, 2002, as revised (Pages 1-66) Part II FORM 10-K TABLE OF CONTENTS Page Part I ---- Item 1. Business..................................................... 1 The Company................................................ 1 Divestitures- International Operations................................. 2 Generating Assets........................................ 3 Utility Regulation......................................... 3 PUCO Rate Matters........................................ 4 NJBPU Rate Matters....................................... 4 PPUC Rate Matters........................................ 5 FERC Rate Matters........................................ 6 Regulatory Accounting.................................... 7 Capital Requirements....................................... 7 Met-Ed Capital Trust and Penelec Capital Trust............. 9 Nuclear Regulation......................................... 9 Nuclear Insurance.......................................... 10 Environmental Matters...................................... 11 Air Regulation........................................... 11 Water Regulation......................................... 12 Waste Disposal........................................... 12 Summary.................................................. 12 Fuel Supply................................................ 13 System Capacity and Reserves............................... 13 Regional Reliability....................................... 14 Competition................................................ 14 Research and Development................................... 15 Executive Officers......................................... 15 FirstEnergy Website........................................ 15 Item 2. Properties................................................... * Item 3. Legal Proceedings............................................ * Item 4. Submission of Matters to a Vote of Security Holders.......... * Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters........................................ * Item 6. Selected Financial Data...................................... 16 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........................ 16 Item 8. Financial Statements and Supplementary Data.................. 16 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure........................ * Part III Item 10. Directors and Executive Officers of the Registrant........... * Item 11. Executive Compensation....................................... * Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters................. * Item 13. Certain Relationships and Related Transactions............... * Item 14. Controls and Procedures...................................... 16 Part IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................................... 16 * Indicates the items that have not been revised and are not included in this Form 10-K/A. Reference is made to the original 10-K for the complete text of such items. PART 1 ITEM 1. BUSINESS The Company FirstEnergy Corp. was organized under the laws of the State of Ohio in 1996. FirstEnergy's principal business is the holding, directly or indirectly, of all of the outstanding common stock of its principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power Company (Penn), The Toledo Edison Company (TE), American Transmission Systems, Incorporated (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). These utility subsidiaries are referred to throughout as "Companies." FirstEnergy's consolidated revenues are primarily derived from electric service provided by its utility operating subsidiaries and the revenues of its other principal subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FSG); MYR Group Inc. (MYR); MARBEL Energy Corporation (MARBEL); GPU Capital, Inc.; and GPU Power, Inc. In addition, FirstEnergy holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FirstEnergy Ventures Corp., FirstEnergy Nuclear Operating Company (FENOC), FirstEnergy Securities Transfer Company, GPU Diversified Holdings, LLC, GPU Telecom Services, Inc., GPU Nuclear, Inc.; FirstEnergy Service Company (FECO); GPU Service, Inc. (GPUS); and GPU Advanced Resources, Inc. The Companies' combined service areas encompass approximately 37,200 square miles in Ohio, New Jersey and Pennsylvania. The areas they serve have a combined population of approximately 11.1 million. OE was organized under the laws of the State of Ohio in 1930 and owns property and does business as an electric public utility in that state. OE also has ownership interests in certain generating facilities located in the Commonwealth of Pennsylvania (see Item 2 - Properties). OE engages in the generation, distribution and sale of electric energy to communities in a 7,500 square mile area of central and northeastern Ohio. OE also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 2.7 million. OE owns all of Penn's outstanding common stock. Penn was organized under the laws of the Commonwealth of Pennsylvania in 1930 and owns property and does business as an electric public utility in that state. Penn is also authorized to do business and owns property in the State of Ohio (see Item 2 - Properties). Penn furnishes electric service to communities in a 1,500 square mile area of western Pennsylvania. The area served by Penn has a population of approximately 0.3 million. CEI was organized under the laws of the State of Ohio in 1892 and does business as an electric public utility in that state. CEI engages in the generation, distribution and sale of electric energy in an area of approximately 1,700 square miles in northeastern Ohio. It also has ownership interests in certain generating facilities in Pennsylvania (see Item 2 - Properties). CEI also engages in the sale, purchase and interchange of electric energy with other electric companies. The area CEI serves has a population of approximately 1.9 million. TE was organized under the laws of the State of Ohio in 1901 and does business as an electric public utility in that state. TE engages in the generation, distribution and sale of electric energy in an area of approximately 2,500 square miles in northwestern Ohio. It also has interests in certain generating facilities in Pennsylvania and Michigan (see Item 2 - Properties). TE also engages in the sale, purchase and interchange of electric energy with other electric companies. The area TE serves has a population of approximately 0.8 million. ATSI was organized under the laws of the State of Ohio in 1998. ATSI owns transmission assets that were formerly owned by OE, CEI and TE (Ohio Companies) and Penn. ATSI owns and operates major, high-voltage transmission facilities, which consist of approximately 7,100 circuit miles (5,778 pole miles) of transmission lines with nominal voltages of 345 kilovolts (kV), 138 kV and 69 kV. There are 37 interconnections with six neighboring control areas. ATSI's transmission system offers gateways into the East through high capacity ties with Pennsylvania-New Jersey-Maryland Interconnection LLC (PJM) through Penelec, Duquesne Light Company (Duquesne) and Allegheny Energy, Inc. (Allegheny), into the North through multiple 345 kV high capacity ties with Michigan Electric Coordination Systems (MEC), and into the South through ties with American Electric Power Company, Inc. (AEP) and Dayton Power & Light Company (DPL). In addition, ATSI is the control area operator for the Ohio Companies and Penn service areas. ATSI plans, operates and maintains the transmission system in accordance with the requirements of the North American Electric Reliability Council and applicable regulatory agencies to ensure reliable service to FirstEnergy's customers (see FERC Rate Matters for discussion on ATSI's participation in the Midwest Independent System Operator, Inc. (MISO)). JCP&L was organized under the laws of the State of New Jersey in 1925 and owns property and does business as an electric public utility in that state. JCP&L provides transmission and distribution services in northern, western and east central New Jersey. The area it serves has a population of approximately 2.5 million. 1 Met-Ed was organized under the laws of the Commonwealth of Pennsylvania in 1922 and owns property and does business as an electric public utility in that state. Met-Ed provides transmission and distribution services in eastern and south central Pennsylvania. The area it serves has a population of approximately 1.1 million. Penelec was organized under the laws of the Commonwealth of Pennsylvania in 1919 and owns property and does business as an electric public utility in that state. Penelec provides transmission and distribution services in western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.7 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves a population of about 13,400 in Waverly, New York and vicinity. FES was organized under the laws of the State of Ohio in 1997 and provides energy-related products and services, and through its FirstEnergy Generation Corp. (FGCO) subsidiary, operates FirstEnergy's nonnuclear generation businesses. FSG is the parent company of several heating, ventilating, air conditioning and energy management companies; MYR is a utility infrastructure construction service company. MARBEL is a natural gas pipeline company whose subsidiaries include MARBEL HoldCo, Inc. a holding company having a 50% ownership interest in Great Lakes Energy Partners, LLC, an oil and natural gas exploration and production venture, and Northeast Ohio Natural Gas Corp., a public utility that provides gas distribution and transportation services. GPU Capital owns and operates electric distribution systems in foreign countries and GPU Power owns and operates generation facilities in foreign countries. FECO and GPUS provide legal, financial and other corporate support services to affiliated FirstEnergy companies. Divestitures International Operations FirstEnergy identified certain former GPU international operations for divestiture within one year of its merger with GPU, Inc. on November 7, 2001. These operations constitute individual "lines of business" as defined in Accounting Principles Board Opinion (APB) No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," with physically and operationally separable activities. Application of Emerging Issues Task Force (EITF) Issue No. 87-11, "Allocation of Purchase Price to Assets to Be Sold," required that expected, pre-sale cash flows, including incremental interest costs on related acquisition debt, of these operations be considered part of the purchase price allocation. Accordingly, subsequent to the merger date, results of operations and incremental interest costs related to these international subsidiaries were not included in FirstEnergy's 2001 Consolidated Statements of Income. Additionally, assets and liabilities of these international operations were segregated under separate captions on the Consolidated Balance Sheet as of December 31, 2001 as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale." Upon completion of its merger with GPU, FirstEnergy accepted an October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase Avon Energy Partners Holdings (Avon), FirstEnergy's wholly owned holding company for Midlands Electricity plc, for $2.1 billion (including the assumption of $1.7 billion of debt). The transaction closed on May 8, 2002 and reflected the March 2002 modification of Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest in Avon for approximately $1.9 billion (including the assumption of $1.7 billion of debt). Proceeds to FirstEnergy included $155 million in cash and a note receivable for approximately $87 million (representing the present value of $19 million per year to be received over six years beginning in 2003) from Aquila for its 79.9 percent interest. FirstEnergy and Aquila together own all of the outstanding shares of Avon through a jointly owned subsidiary, with each company having an ownership voting interest. Originally, in accordance with applicable accounting guidance, the earnings of those foreign operations were not recognized in current earnings from the date of the GPU acquisition. However, as a result of the decision to retain an ownership interest in Avon, EITF Issue No. 90-6, "Accounting for Certain Events Not Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be Sold" required FirstEnergy to reallocate the purchase price of GPU based on amounts as of the purchase date as if Avon had never been held for sale, including reversal of the effects of having applied EITF Issue No. 87-11, to the transaction. The effect of reallocating the purchase price and reversal of the effects of EITF Issue No. 87-11, including the allocation of capitalized interest, has been reflected in the Consolidated Statement of Income for the year ended December 31, 2002 by reclassifying certain revenue and expense amounts related to activity during the quarter ended March 31, 2002 to their respective income statement classifications. See Note 2(L) of Notes to FirstEnergy's Consolidated Financial Statements for the effects of the change in classification. In the fourth quarter of 2002, FirstEnergy recorded a $50 million charge ($32.5 million net of tax) to reduce the carrying value of its remaining 20.1 percent interest. GPU's former Argentina operations were also identified by FirstEnergy for divestiture within one year of the merger. FirstEnergy determined the fair value of its Argentina operations, GPU Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa), based on the best available information as of the date of the merger. Subsequent to that date, a number of economic events have occurred in Argentina which may have an impact on FirstEnergy's ability to realize Emdersa's estimated fair value. These events include currency devaluation, restrictions on repatriation of cash, and the anticipation of future asset sales in that region by competitors. FirstEnergy did not reach a 2 definitive agreement to sell Emdersa as of December 31, 2002. Therefore, these assets were no longer classified as "Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2002 and Emdersa's results of operations were included in FirstEnergy's 2002 Consolidated Statement of Income. Additionally, under EITF Issue No. 90-6, FirstEnergy recorded in the fourth quarter of 2002 a one-time, non-cash charge included as a "Cumulative Adjustment for Retained Businesses Previously Held for Sale" on its 2002 Consolidated Statement of Income related to Emdersa's cumulative results of operations from November 7, 2001 through September 30, 2002. The amount of this one-time, after-tax charge was $93.7 million, or $0.32 per share of common stock (comprised of $108.9 million in currency transaction losses arising principally from U.S. dollar denominated debt, offset by $15.2 million of operating income). See Note 2(L) of Notes to First Energy's Consolidated Financial Statements for the effects of the change in classification. On October 1, 2002, FirstEnergy began consolidating the results of Emdersa's operations in its financial statements. In addition to the currency transaction losses of $108.9 million, FirstEnergy recognized a currency translation adjustment (CTA) in other comprehensive income (OCI) of $91.5 million as of December 31, 2002, which reduced FirstEnergy's common stockholders' equity. This adjustment represents the impact of translating Emdersa's financial statements from its functional currency to the U.S. dollar for financial reporting in conformity with accounting principles generally accepted in the United States (GAAP). On April 18, 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. As a result of the abandonment, FirstEnergy will recognize a one-time, non-cash charge of $63 million, or $0.21 per share of common stock in the second quarter of 2003. This charge is the result of realizing the CTA losses through the current period earnings ($90 million, or $0.30 per share), partially offset by the gain recognized from eliminating its investment in Emdersa ($27 million, or $0.09 per share). Since FirstEnergy has previously recorded $90 million of CTA adjustments in OCI, the net effect of the $63 million charge will be an increase in common stockholders' equity of $27 million. The $63 million charge does not include the anticipated income tax benefits related to the abandonment. These tax benefits will be fully reserved during the second quarter. FirstEnergy anticipates tax benefits of approximately $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million tax benefits would reduce goodwill recognized in connection with the acquisition of GPU. Generating Assets In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 megawatts (MW) to NRG Energy Inc. On August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves the right to pursue legal action against NRG, its affiliate and its parent, Xcel Energy, for damages, based on the anticipatory breach of the agreement. On February 25, 2003, the U.S. Bankruptcy Court in Minnesota approved FirstEnergy's request for arbitration against NRG. In December 2002, FirstEnergy announced it would retain ownership of these plants after reviewing other bids it subsequently received from other parties who had expressed interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, it reflected approximately $74 million ($43 million net of tax), or $0.15 per share of common stock, of previously unrecognized depreciation and transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statement of Income. Utility Regulation As a registered public utility holding company, FirstEnergy is subject to regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act). The SEC has determined that the electric facilities of the Companies constitute a single integrated public utility system under the standards of the 1935 Act. The 1935 Act regulates FirstEnergy with respect to accounting, the issuance of securities, the acquisition and sale of utility assets, securities or any other interest in any business, and entering into, and performance of, service, sales and construction contracts among its subsidiaries, and certain other matters. The 1935 Act also limits the extent to which FirstEnergy may engage in nonutility businesses or acquire additional utility businesses. Each of the Companies' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the state in which each operates - in Ohio by the Public Utilities Commission of Ohio (PUCO), in New Jersey by the New Jersey Board of Public Utilities (NJBPU) and in Pennsylvania by the Pennsylvania Public Utility Commission (PPUC). With respect to their wholesale and interstate electric operations and rates, the Companies are subject to regulation, including regulation of their accounting policies and practices, by the Federal Energy Regulatory Commission (FERC). Under Ohio law, municipalities may regulate rates, subject to appeal to the PUCO if not acceptable to the utility. 3 In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included the similar provisions which are reflected in the Companies' respective state regulatory plans: o allowing the Companies' electric customers to select their generation suppliers; o establishing provider of last resort (PLR) obligations to customers in the Companies' service areas; o allowing recovery of potentially stranded investment (sometimes referred to as transition costs); o itemizing (unbundling) the current price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; o deregulating the Companies' electric generation businesses; and o continuing regulation of the Companies' transmission and distribution systems. PUCO Rate Matters In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. In July 2000, the PUCO approved FirstEnergy's transition plan for the OE, CEI and TE (Ohio Companies) as modified by a settlement agreement with major parties to the transition plan. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation" to OE's generation business and the nonnuclear generation businesses of CEI and TE was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $4.0 billion net of deferred income taxes (OE-$1.6 billion, CEI-$1.6 billion and TE-$0.8 billion) and transition costs related to regulatory assets as filed of $2.9 billion net of deferred income taxes (OE-$1.0 billion, CEI-$1.4 billion and TE-$0.5 billion), with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.4 billion, net of deferred income taxes, (OE-$1.0 billion, CEI-$0.2 billion and TE-$0.2 billion) of impaired generating assets recognized as regulatory assets as described further below, $2.4 billion, net of deferred income taxes, (OE-$1.2 billion, CEI-$0.4 billion and TE-$0.8 billion) of above market operating lease costs and $0.8 billion, net of deferred income taxes, (CEI-$0.5 billion and TE-$0.3 billion) of additional plant costs that were reflected on CEI's and TE's regulatory financial statements. Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 megawatts (MW) of generation capacity through 2005 at established prices for sales to the Ohio Companies' retail customers. Customer prices are frozen through the five-year market development period except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Ohio Companies were authorized increases in annual revenues aggregating approximately $50 million (OE-$41 million, CEI-$4 million and TE-$5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation. FirstEnergy's Ohio 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 - recovery will be accomplished by extending the respective transition cost recovery period. If the customer shopping goals established in the agreement had not been achieved by the end of 2005, the transition cost recovery periods could have been shortened for OE, CEI and TE to reduce recovery by as much as $500 million (OE - $250 million, CEI - $170 million and TE - $80 million). The Ohio Companies achieved all of their required 20% customer shopping goals in 2002. Accordingly, FirstEnergy believes that there will be no regulatory action reducing the recoverable transition costs. NJBPU Rate Matters JCP&L's 2001 Final Decision and Order (Final Order) with respect to its rate unbundling, stranded cost and restructuring filings confirmed rate reductions set forth in its 1999 Summary Order, which remain in effect at increasing levels through July 2003. The Final Order also confirmed the establishment of a non-bypassable societal benefits charge (SBC) to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable market transition charge (MTC) primarily to recover stranded costs. The NJBPU has deferred making a final determination of the net proceeds and stranded costs related to prior generating 4 asset divestitures until JCP&L's request for an Internal Revenue Service (IRS) ruling regarding the treatment of associated federal income tax benefits is acted upon. Should the IRS ruling support the return of the tax benefits to customers, there would be no effect to FirstEnergy's or JCP&L's net income since the contingency existed prior to the merger. In addition, the Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. In February 2002, JCP&L received NJBPU authorization to issue $320 million of transition bonds to securitize the recovery of these costs. The NJBPU order also provided for a usage-based non-bypassable transition bond charge and for the transfer of the bondable transition property to another entity. JCP&L sold $320 million of transition bonds through its wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 - those bonds are recognized on the Consolidated Balance Sheet. JCP&L's PLR obligation to provide basic generation service (BGS) to non-shopping customers is supplied almost entirely from contracted and open market purchases. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under nonutility generation (NUG) agreements exceed amounts collected through BGS and MTC rates. As of December 31, 2002, the accumulated deferred cost balance totaled approximately $549 million. The NJBPU also allowed securitization of JCP&L's deferred balance to the extent permitted by law upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization. Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. On August 1, 2002, JCP&L submitted two rate filings with the NJBPU. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization discussed above. Hearings began in February 2003. On March 18, 2003, a report prepared by independent auditors addressing costs deferred by JCP&L from August 1, 1999 through July 31, 2002, was transmitted to the Office of Administrative Law, where JCP&L's rate case is being heard. While the auditors concluded that JCP&L's energy procurement strategy and process was reasonable and prudent, they identified potential disallowances totaling $17.3 million. The report subjected $436 million of deferred costs to a retrospective prudence review during a period of extreme price uncertainty and volatility in the energy markets. Although JCP&L disagrees with the potential disallowances, it is pleased with the report's major conclusions and overall tone. Hearings concluded on April 28, 2003, and initial briefs were filed on May 7, 2003. The Administrative Law Judge's recommended decision is due by the end of June 2003 and the NJBPU's subsequent decision is due in July 2003. In 1997, the NJBPU authorized JCP&L to recover from customers, subject to possible refund, $135 million of costs incurred in connection with a 1996 buyout of a power purchase agreement. JCP&L has recovered the full $135 million; the NJBPU has established a procedural schedule to take further evidence with respect to the buyout to enable it to make a final prudence determination contemporaneously with the resolution of the pending rate case. In December 2001, the NJBPU authorized the auctioning of BGS for the period from August 1, 2002 through July 31, 2003 to meet the electricity demands of all customers who have not selected an alternative supplier. The auction results were approved by the NJBPU in February 2002, removing JCP&L's BGS obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In February 2003, the NJBPU approved the BGS auction results for the period beginning August 1, 2003. The auction covered a fixed price bid (applicable to all residential and smaller commercial and industrial customers) and an hourly price bid (applicable to all large industrial customers) process. JCP&L will sell all self-supplied energy (NUGs and owned generation) to the wholesale market with offsets to its deferred energy balances. PPUC Rate Matters The PPUC authorized 1998 rate restructuring plans for Penn, Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Similar to JCP&L's situation, if the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income since the contingency existed prior to the merger. As a result of their generating asset divestitures, Met-Ed and Penelec obtained their supply of electricity to meet their PLR obligations almost entirely from contracted and open market purchases. In 2000, Met-Ed and Penelec filed a petition with the PPUC seeking permission to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates; the PPUC subsequently consolidated this petition in January 2001 with the FirstEnergy/GPU merger proceeding. 5 In June 2001, the PPUC entered orders approving the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the merger and provided Met-Ed and Penelec PLR deferred accounting treatment for energy costs. The PPUC permitted Met-Ed and Penelec to defer for future recovery the difference between their actual energy costs and those reflected in their capped generation rates, retroactive to January 1, 2001. Correspondingly, in the event that energy costs incurred by Met-Ed and Penelec would be below their respective capped generation rates, that difference would have reduced costs that had been deferred for recovery in future periods. This PLR deferral accounting procedure was denied in a court decision discussed below. Met-Ed's and Penelec's PLR obligations extend through December 31, 2010; during that period competitive transition charge (CTC) revenues would have been applied to their stranded costs. Met-Ed and Penelec would have been permitted to recover any remaining stranded costs through a continuation of the CTC after December 31, 2010 through no later than December 31, 2015. Any amounts not expected to be recovered by December 31, 2015 would have been written off at the time such nonrecovery became probable. Several parties had filed Petitions for Review in June and July 2001 with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders. On February 21, 2002, the Court affirmed the PPUC decision regarding the FirstEnergy/GPU merger, remanding the decision to the PPUC only with respect to the issue of merger savings. The Court reversed the PPUC's decision regarding the PLR obligations of Met-Ed and Penelec, and rejected those parts of the settlement that permitted the companies to defer for accounting purposes the difference between their wholesale power costs and the amount that they collect from retail customers. FirstEnergy and the PPUC each filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court on March 25, 2002, asking it to review the Commonwealth Court decision. Also on March 25, 2002, Citizens Power filed a motion seeking an appeal of the Commonwealth Court's decision to affirm the FirstEnergy and GPU merger with the Pennsylvania Supreme Court. In September 2002, FirstEnergy established reserves for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287.1 million. The reserves reflected the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. FirstEnergy recorded an aggregate non-cash charge to income of $55.8 million ($32.6 million net of tax), or $0.11 per share of common stock, for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million. On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the PPUC's order approving the merger between FirstEnergy and GPU, let stand the Commonwealth Court's denial of PLR rate relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. Because FirstEnergy had already reserved for the deferred energy costs and FES has largely hedged the anticipated PLR energy supply requirements for Met-Ed and Penelec through 2005 as discussed further below, FirstEnergy, Met-Ed and Penelec believe that the disallowance of continued CTC recovery of PLR costs will not have a future adverse financial impact. Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to their FES affiliate through a wholesale power sale agreement. The PLR sale, which initially ran through the end of 2002, was extended through December 2003 and will be automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES assumes the supply obligation and the energy supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at or below the shopping credit for their uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of Met-Ed's and Penelec's unfilled PLR obligation through 2005, the period during which deferred accounting was previously allowed under the PPUC's order. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and amounts recovered through their capped generation rates. FERC Rate Matters The Companies provide wholesale power and transmission service subject to the jurisdiction of the FERC. Following the FirstEnergy/GPU merger the transmission facilities of JCP&L, Met-Ed and Penelec continue to be operated by PJM. PJM was approved by the FERC as a regional transmission organization (RTO) on December 20, 2002. Transmission service over the facilities of FirstEnergy's PJM operating companies is provided under the PJM Open Access Tariff. On December 20, 2001, the FERC issued an order that reversed prior findings that the Alliance RTO had adequate scope and concluded that there should be only one RTO (the Midwest ISO) in the Midwest. The FERC directed the former Alliance companies, including ATSI, to file their new RTO choices with the FERC. On July 31, 2002, the FERC approved the RTO choices of the former Alliance companies, but directed the formation of a single market for the MISO and PJM by October 1, 2004. This single market would include all of the generation and transmission facilities of the FirstEnergy operating companies. FERC also initiated an investigation pursuant to Section 206 of the Federal 6 Power Act concerning the existing "through and out" transmission rates between the MISO and PJM. Hearings on this proceeding concluded in January 2003, and an Initial Decision is expected from the Administrative Law Judge by March 28, 2003. ATSI proposes to transfer its transmission facilities in the East Central Area Reliability Agreement (ECAR) area to the MISO RTO as part of GridAmerica, LLC, an independent transmission company. On December 19, 2002, the FERC conditionally accepted GridAmerica's filing to become an independent transmission company within the MISO. GridAmerica will operate ATSI's transmission facilities and expects to begin operations in the second quarter of 2003 subject to approval of certain compliance filings with the FERC. The compliance filings were made by the GridAmerica companies (ATSI, Ameren Services Company and Northern Indiana Public Service Company) on January 31, 2003 and February 19, 2003. On July 31, 2002, the FERC initiated a rulemaking designed to standardize the terms and conditions under which wholesale electric service is provided in regions with independent transmission operators, including the MISO and PJM. FirstEnergy filed comments and reply comments on the proposed rule. Implementation of the proposed rule was expected to begin on July 31, 2003. However, the FERC has indicated that it will delay implementation of Standard Market Design in order to accommodate substantial changes in the proposed rule. A FERC "white paper" is expected to be issued in April 2003 outlining changes in the proposed rule. Regulatory Accounting All of the Companies' regulatory assets (deferred costs) are expected to continue to be recovered under provisions of the Ohio transition plan and the respective Pennsylvania and New Jersey regulatory plans. The application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), has been discontinued with respect to the Companies' generation operations. Capital Requirements Capital expenditures for the Companies, FES and FirstEnergy's other subsidiaries for the years 2002 through 2007, excluding nuclear fuel, are shown in the following table. Such costs include expenditures for the betterment of existing facilities and for the construction of generating capacity, facilities for environmental compliance, transmission lines, distribution lines, substations and other assets. See "Environmental Matters" below with regard to possible environmental-related expenditures not included in the forecast. Capital Expenditures Forecast 2002 -------------------------------------- Actual 2003 2004-2007 Total ------ ---- --------- ----- (In millions) OE.................. $ 81 $ 86 $ 182 $ 268 Penn................ 40 53 70 123 CEI................. 137 96 216 312 TE.................. 91 54 115 169 JCP&L............... 100 102 360 462 Met-Ed.............. 43 53 235 288 Penelec............. 49 54 274 328 ATSI................ 27 25 106 131 FES................. 185 124 699 823 Other subsidiaries.. 151 80 67 147 ---- ---- ------ ------ Total............... $904 $727 $2,324 $3,051 During the 2003-2007 period, maturities of, and sinking fund requirements for, long-term debt and preferred stock of FirstEnergy and its subsidiaries are: Preferred Stock and Long-Term Debt Redemption Schedule ------------------------------------------ 2003 2004-2007 Total ---- --------- ----- (In millions) OE.............................. $ 210 $ 207 $ 417 Penn............................ 42 52 94 CEI............................. 146 704 850 TE.............................. 116 245 361 JCP&L........................... 174 510 684 Met-Ed.......................... 60 292 352 Penelec......................... -- 137 137 FirstEnergy..................... -- 1,695 1,695 Other subsidiaries.............. 327 40 367 ------ ------ ------ Total........................... $1,075 $3,882 $4,957 7 The Companies' and FES's respective investments for additional nuclear fuel, and nuclear fuel investment reductions as the fuel is consumed, during the 2003-2007 period are presented in the following table. The table also displays the Companies' operating lease commitments, net of capital trust cash receipts for the 2003-2007 period.
Nuclear Fuel Forecasts ----------------------------------------------------- Net New Investments Consumption Operating Lease Commitments ----------------------- ------------------------- ---------------------------- 2003 2004-2007 Total 2003 2004-2007 Total 2003 2004-2007 Total ---- --------- ----- ---- --------- ----- ---- --------- ----- (In millions) OE.................. $23 $ 32 $ 55 $24 $ 27 $ 51 $ 74 $321 $395 Penn................ 19 23 42 17 17 34 -- 1 1 CEI................. 15 38 53 28 31 59 (2) 70 68 TE.................. 12 22 34 19 21 40 75 311 386 JCP&L............... -- -- -- -- -- -- 3 6 9 Met-Ed.............. -- -- -- -- -- -- 3 5 8 FES................. -- 301 301 -- 299 299 -- -- -- --- ---- ---- --- ---- ---- ---- ---- ---- Total............... $69 $416 $485 $88 $395 $483 $153 $714 $867
Short-term borrowings outstanding as of December 31, 2002, consisted of $1.093 billion of bank borrowings (FirstEnergy-$910.0 million, OE-$22.6 million and FSG-$0.5 million) and $159.7 million of OES Capital, Incorporated commercial paper. OES Capital is a wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable. OES Capital can borrow up to $170 million under a receivables financing agreement at rates based on certain bank commercial paper. FirstEnergy had $177 million available under $1.5 billion of revolving lines of credit as of December 31, 2002. FirstEnergy may borrow under its facility and could transfer any of its borrowings to affiliated companies. OE and MYR had $19 million and $46 million, respectively, of unused bank facilities as of December 31, 2002. An additional source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. In 2002, the holding company received $447 million of cash dividends on common stock from its subsidiaries. Based on their present plans, the Companies could provide for their cash requirements in 2003 from the following sources: funds to be received from operations; available cash and temporary cash investments as of December 31, 2002 (Company's nonutility subsidiaries-$93 million, OE-$20 million, Penn-$1 million, CEI-$30 million, TE-$21 million, JCP&L-$5 million, Met-Ed-$16 million and Penelec-$10 million); the issuance of long-term debt (for refunding purposes); and funds available under revolving credit arrangements. The extent and type of future financings will depend on the need for external funds as well as market conditions, the maintenance of an appropriate capital structure and the ability of the Companies to comply with coverage requirements in order to issue first mortgage bonds and preferred stock. The Companies will continue to monitor financial market conditions and, where appropriate, may take advantage of economic opportunities to refund debt and preferred stock to the extent that their financial resources permit. The coverage requirements contained in the first mortgage indentures under which the Companies issue first mortgage bonds provide that, except for certain refunding purposes, the Companies may not issue first mortgage bonds unless applicable net earnings (before income taxes), calculated as provided in the indentures, for any period of twelve consecutive months within the fifteen calendar months preceding the month in which such additional bonds are issued, are at least twice annual interest requirements on outstanding first mortgage bonds, including those being issued. Under OE's first mortgage indenture, the availability of property additions is more restrictive than the earnings test at the present time and would limit the amount of first mortgage bonds issuable against property additions to $172 million. OE is currently able to issue $1.195 billion principal amount of first mortgage bonds against previously retired bonds without the need to meet the above restrictions. Under Penn's first mortgage indenture, other requirements also apply and are more restrictive than the earnings test at the present time. Penn is currently able to issue $323 million principal amount of first mortgage bonds, with up to $150 million of such amount issuable against property additions; the remainder could be issued against previously retired bonds. CEI and TE can issue $379 million and $144 million principal amount of first mortgage bonds against a combination of previously retired bonds and property additions, respectively. TE cannot currently issue first mortgage bonds. JCP&L, Met-Ed and Penelec are able to issue $393 million, $74 million and $7 million principal amount, respectively, of first mortgage bonds against previously retired bonds. OE's, Penn's, TE's and JCP&L's respective articles of incorporation prohibit the sale of preferred stock unless applicable gross income, calculated as provided in the articles of incorporation, is equal to at least 1-1/2 times the aggregate of the annual interest requirements on indebtedness and annual dividend requirements on preferred stock outstanding immediately thereafter. Based upon earnings for 2002, an assumed dividend rate of 9%, and no additional indebtedness, OE, Penn and JCP&L would be permitted, under the earnings coverage test contained in their respective charters, to issue at least $2.8 billion, $251 million and $1.2 billion of preferred stock, respectively; TE cannot currently issue preferred stock. There are no restrictions on the ability of CEI, Met-Ed and Penelec to issue preferred stock. 8 To the extent that coverage requirements or market conditions restrict the Companies' abilities to issue desired amounts of first mortgage bonds or preferred stock, the Companies may seek other methods of financing. Such financings could include the sale of preferred and/or preference stock or of such other types of securities as might be authorized by applicable regulatory authorities which would not otherwise be sold and could result in annual interest charges and/or dividend requirements in excess of those that would otherwise be incurred. Met-Ed Capital Trust and Penelec Capital Trust In 1999, Met-Ed Capital Trust, a wholly owned subsidiary of Met-Ed, issued $100 million of trust preferred securities (Met-Ed Trust Preferred Securities) at 7.35%, due 2039. The sole assets of Met-Ed Capital Trust are the 7.35% Cumulative Preferred Securities of Met-Ed Capital II, L.P. (Met-Ed Partnership Preferred Securities) and its only revenues are the quarterly cash distributions it receives on the Met-Ed Partnership Preferred Securities. Each Met-Ed Trust Preferred Security represents a Met-Ed Partnership Preferred Security. Met-Ed Capital II, L.P. is a wholly-owned subsidiary of Met-Ed and the sponsor of Met-Ed Capital Trust. The sole assets of Met-Ed Capital II, L.P. are Met-Ed's 7.35% Subordinated Debentures, Series A, due 2039, which have an aggregate principal amount of $103.1 million. Distributions were made on the Trust Preferred Securities during 2002 in the aggregate amount of $7,350,000. Expenses of Met-Ed Trust for 2002 were approximately $13,000, all of which were paid by Met-Ed Preferred Capital II, Inc., the general partner of Met-Ed Capital II, L.P. The Trust Preferred Securities are issued in book-entry form only so that there is only one holder of record. Met-Ed has fully and unconditionally guaranteed the Met-Ed Partnership Preferred Securities, and, therefore, the Met-Ed Trust Preferred Securities. In 1999, Penelec Capital Trust, a wholly owned subsidiary of Penelec, issued $100 million of trust preferred securities (Penelec Trust Preferred Securities) at 7.34%, due 2039. The sole assets of Penelec Capital Trust are the 7.34% Cumulative Preferred Securities of Penelec Capital II, L.P. (Penelec Partnership Preferred Securities) and its only revenues are the quarterly cash distributions it receives on the Penelec Partnership Preferred Securities. Each Penelec Trust Preferred Security represents a Penelec Partnership Preferred Security. Penelec Capital II, L.P. is a wholly-owned subsidiary of Penelec and the sponsor of Penelec Capital Trust. The sole assets of Penelec Capital II, L.P. are Penelec's 7.34% Subordinated Debentures, Series A, due 2039, which have an aggregate principal amount of $103.1 million. Distributions were made on the Trust Preferred Securities during 2002 in the aggregate amount of $7,340,000. Expenses of Penelec Trust for 2002 were approximately $13,000, all of which were paid by Penelec Preferred Capital II, Inc., the general partner of Penelec Capital II, L.P. The Trust Preferred Securities are issued in book-entry form only so that there is only one holder of record. Penelec has fully and unconditionally guaranteed the Penelec Partnership Preferred Securities, and, therefore, the Penelec Trust Preferred Securities. Nuclear Regulation The construction, operation and decommissioning of nuclear generating units are subject to the regulatory jurisdiction of the Nuclear Regulatory Commission (NRC) including the issuance by it of construction permits, operating licenses, and possession only licenses for decommissioning reactors. The NRC's procedures with respect to the amendment of nuclear reactor operating licenses afford opportunities for interested parties to request adjudicatory hearings on health, safety and environmental issues subject to meeting NRC "standing" requirements. The NRC may require substantial changes in operation or the installation of additional equipment to meet safety or environmental standards, subject to the backfit rule requiring the NRC to justify such new requirements as necessary for the overall protection of public health and safety. The possibility also exists for modification, denial or revocation of licenses. As a result of the merger with GPU, FirstEnergy now owns the Three Mile Island Unit 2 (TMI-2) and the Saxton Nuclear Experimental Facility. Both facilities are in various stages of decommissioning. TMI-2 is in a post-defueling monitored storage condition, with decommissioning planned in 2014. Saxton is in the final stages of decommissioning, with license termination scheduled for the end of 2003 and final site restoration scheduled for the first quarter of 2003. Beaver Valley Unit 1 was placed in commercial operation in 1976, and its operating license expires in 2016. Davis-Besse was placed in commercial operation in 1977, and its operating license expires in 2017. Perry Unit 1 and Beaver Valley Unit 2 were placed in commercial operation in 1987, and their operating licenses expire in 2026 and 2027, respectively. Davis-Besse, which is operated by FENOC, began its scheduled refueling outage on February 16, 2002. The plant was originally scheduled to return to service by the end of March 2002. During the refueling outage, visual and ultrasonic testings were conducted on all 69 of the Control Rod Drive Mechanism penetration nozzles. This testing was performed to check for the kind of circular or circumferential cracking in these nozzles that had been found at some other plants similar in design and vintage to Davis-Besse. Based on the inspection and test results, five nozzles were scheduled for repair during the refueling outage. As repair work began on one of the nozzles, FENOC found corrosion in the reactor vessel head near some of the penetration holes, created by boric acid deposits from leaks in the nozzles. As a result, the NRC issued a confirmatory action letter stating that restart of the plant would be subject to prior NRC approval, and it established an Inspection Manual Chapter 0350 Oversight Panel to ensure close NRC oversight of Davis-Besse's corrective actions. 9 In response to the reactor vessel head degradation, FENOC initiated a number of root cause analyses and other assessments, and established a Return to Service Plan to correct the causes and ensure a safe and reliable return to service. The Return to Service Plan includes actions to: replace the reactor vessel head, inspect and correct other components in the containment that may have been affected by boric acid, review important systems and programs to ensure their readiness for restart, and improve management and human performance. FENOC has completed many of the actions under the Return to Service Plan and is currently implementing corrective actions and performing tests to ensure the readiness of the plant to restart. FENOC anticipates that Davis-Besse will be ready for restart in the first half of the summer of 2003. However, the NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. In 2002, FENOC spent approximately $115 million in additional nuclear-related operation and maintenance costs, approximately $120 million in replacement power costs and approximately $63 million in capital expenditures related to the reactor head and restart. For 2003, FENOC expects to spend approximately $50 million in additional nuclear-related operation and maintenance costs and approximately $12-18 million in replacement power costs per month. These costs could increase if the length of the outage increases. The NRC has promulgated and continues to promulgate orders and regulations related to the safe operation of nuclear power plants and standards for decommissioning clean-up and final license termination. The Companies cannot predict what additional orders and regulations (including post-September 11, 2001 security enhancements) may be promulgated, design changes required or the effect that any such regulations or design changes or additional clean-up standards for final site release, or the consideration thereof, may have upon their nuclear plants. Although the Companies have no reason to anticipate an accident at any of their nuclear plants, if such an accident did happen, it could have a material but currently undeterminable adverse effect on FirstEnergy's consolidated financial position. In addition, such an accident at any operating nuclear plant, whether or not owned by the Companies, could result in regulations or requirements that could affect the operation, licensing, or decommissioning of plants that the Companies do own with a consequent but currently undeterminable adverse impact, and could affect the Companies' abilities to raise funds in the capital markets. Nuclear Insurance The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $9.5 billion (assuming 105 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $300 million; and (ii) $9.2 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $88.1 million (but not more than $10 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, the Companies' maximum potential assessment under these provisions would be $352.4 million (OE-$94.2 million, Penn-$74.0 million, CEI-$106.3 million and TE-$77.9 million) per incident but not more than $40.0 million (OE-$10.7 million, Penn-$8.4 million, CEI-$12.1 million and TE-$8.8 million) in any one year for each incident. In addition to the public liability insurance provided pursuant to the Price-Anderson Act, the Companies have also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. The Companies are members of Nuclear Electric Insurance Limited (NEIL) which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, the Companies have policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.182 billion (OE-$315 million, Penn-$222 million, CEI-$382 million and TE-$263 million) for replacement power costs incurred during an outage after an initial 12-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. The Companies' present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $11.1 million (OE-$3.1 million, Penn-$2.2 million, CEI-$3.4 million and TE-$2.4 million). The Companies are insured as to their respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, $2.75 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. The Companies pay annual premiums for this coverage and are liable for retrospective assessments of up to approximately $57.3 million (OE-$15.5 million, Penn-$10.9 million, CEI-$17.9 million, TE-$12.2 million, JCP&L-$0.2 million, Met-Ed-$0.4 million and Penelec-$0.2 million) during a policy year. 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 10 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. The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.06 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. The Companies are unable to predict what effect these requirements may have on the availability of insurance proceeds to the Companies for the Companies' bondholders. Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $159 million, which is included in the construction forecast provided under "Capital Requirements" for 2003 through 2007. Air Regulation Under the provisions of the Clean Air Act of 1970, the States of Ohio and New Jersey and the Commonwealth of Pennsylvania have adopted ambient air quality standards, and related emission limits, including limits for sulfur dioxide (SO2) and particulates. In addition, the U.S. Environmental Protection Agency (EPA) promulgated an SO2 regulatory plan for Ohio which became effective for OE's, CEI's and TE's plants in 1977. Generating plants to be constructed in the future and some future modifications of existing facilities will be covered not only by the applicable state standards but also by EPA emission performance standards for new sources. In Ohio, New Jersey and Pennsylvania the construction or certain modifications of emission sources requires approval from appropriate environmental authorities, and the facilities involved may not be operated unless a permit or variance to do so has been issued by those same authorities. The Companies are required to meet federally approved 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 EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies believe they are in compliance with the current SO2 and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio, New Jersey 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 and the District of Columbia, including New Jersey, Ohio and Pennsylvania, 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 requires compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. The Companies continue to evaluate their compliance plans and other compliance options. In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals found constitutional and other defects in the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating ultra-fine particulates but found defects in the new NAAQS rules for ozone and decided that the EPA must revise those rules. The future cost of compliance with these regulations may be substantial and will depend if and how they are ultimately implemented by the states in which the Companies operate affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio, for which hearings began on February 3, 2003. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to 11 require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of these proceedings, FirstEnergy believes the Sammis Plant is in full compliance with the Clean Air Act and the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. Water Regulation 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, New Jersey 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, New Jersey and Pennsylvania have assumed such authority. Waste Disposal As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. The Companies have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of December 31, 2002, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through its SBC. The Companies have total accrued liabilities aggregating approximately $54.3 million as of December 31, 2002. In 1980, Congress passed the Low-Level Radioactive Waste Policy Act which provides that the disposal of low-level radioactive waste is the responsibility of the state where such waste is generated. The Act encourages states to form compacts among themselves to develop regional disposal facilities. Failure by a state or compact to begin implementation of a program could result in access denial to the two facilities currently accepting low-level radioactive waste. Ohio is part of the Midwest Compact and has responsibility for siting and constructing a disposal facility. On June 26, 1997, the Midwest Compact Commission (Compact) voted to cease all siting activities in the host state of Ohio and to dismantle the Ohio Low-Level Radioactive Waste Facility Development Authority, the statutory agency charged with siting and constructing the low-level radioactive waste disposal facility. While the Compact remains intact, it has no plans to site or construct a low-level radioactive waste disposal facility in the Midwest. The Companies continue to ship low-level radioactive waste from their nuclear facilities to the Barnwell, South Carolina waste disposal facility. Summary Environmental controls are still developing and require, in many instances, balancing the needs for additional quantities of energy in future years and the need to protect the environment. As a result, the Companies cannot now estimate the precise effect of existing and potential regulations and legislation upon any of their existing and proposed facilities and operations or upon their ability to issue additional first mortgage bonds under their respective mortgages. These mortgages contain covenants by the Companies to observe and conform to all valid governmental requirements at the time applicable unless in course of contest, and provisions which, in effect, prevent the issuance of additional bonds if there is a completed default under the mortgage. The provisions of each of the mortgages, in effect, also require, in the opinion of counsel for the respective Companies, that certification of property additions as the basis for the issuance of bonds or other action under the mortgages be accompanied by an opinion of counsel that the company certifying such property additions has all governmental permissions at the time necessary for its then current ownership and operation of such property additions. The Companies intend to contest any requirements they deem unreasonable or impossible for compliance or otherwise contrary to the public interest. Developments in these and other areas of regulation may require the Companies to modify, supplement or replace equipment and facilities, and may 12 delay or impede the construction and operation of new facilities, at costs which could be substantial. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy believes it is in material compliance with existing regulations but is unable to predict whether environmental regulations will change and what, if any, the effects of such change would be. Fuel Supply The Companies' sources of generation during 2002 were: Fossil Nuclear ------ ------- OE.................... 74.5% 25.5% Penn.................. 34.6% 65.4% CEI................... 67.3% 32.7% TE.................... 61.8% 38.2% Total FirstEnergy..... 65.6% 34.4% Generation from JCP&L's and Met-Ed's hydro and combustion turbine generation facilities was minimal in 2002. FirstEnergy currently has long-term coal contracts to provide approximately 12,400,000 tons for the year 2003. The contracts are shared among the Companies based on various economic considerations. This contract coal is produced primarily from mines located in Pennsylvania, Kentucky and West Virginia. The contracts expire at various times through December 31, 2019. The Companies estimate their 2003 coal requirements to be approximately 18,860,000 tons (OE - 7,250,000, Penn - 6,000,000, CEI - 4,170,000, and TE - 1,440,000) to be met from the long-term contracts discussed above and spot market purchases. See "Environmental Matters" for factors pertaining to meeting environmental regulations affecting coal-fired generating units. FirstEnergy has contracts for uranium material and conversion services through 2006. The enrichment services are contracted for the majority of the enrichment requirements for nuclear fuel through 2006. Fabrication services for fuel assemblies are contracted for the next four reloads for Beaver Valley Unit 1, the next three reloads for Beaver Valley Unit 2 (through approximately 2007 and 2006, respectively), the next two reloads for Davis-Besse (through approximately 2007) and through the operating license period for Perry (through approximately 2026). In addition to the existing commitments, FirstEnergy intends to make additional arrangements for the supply of uranium and for the subsequent conversion, enrichment, fabrication, and waste disposal services. On-site spent fuel storage facilities are expected to be adequate for Perry through 2011; facilities at Beaver Valley Units 1 and 2 are expected to be adequate through 2018 and 2009, respectively. With the plant modifications completed in 2002, Davis-Besse has adequate storage through the remainder of its operating license period. After current on-site storage capacity is exhausted, additional storage capacity will have to be obtained either through plant modifications, interim off-site disposal, or permanent waste disposal facilities. The Federal Nuclear Waste Policy Act of 1982 provides for the construction of facilities for the permanent disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities; however, the selection of a suitable site is embroiled in the political process. FirstEnergy has contracts with the U.S. Department of Energy (DOE) for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. On February 15, 2002, President Bush approved the DOE's recommendation of Yucca Mountain for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The recommendation by President Bush enables the process to proceed to the licensing phase. Based on the DOE schedule published in the July 1999 Draft Environmental Impact Statement, the Yucca Mountain Repository is currently projected to start receiving spent fuel in 2010. FirstEnergy intends to make additional arrangements for storage capacity as a contingency for further delays with the DOE acceptance of spent fuel for disposal past 2010. System Capacity and Reserves The 2002 net maximum hourly demand for each of the Companies was: OE-6,757 MW (including an additional 387 MW of firm power sales under a contract which extends through 2005) on August 1, 2002; Penn-969 MW (including an additional 63 MW of firm power sales under a contract which extends through 2005) on July 29, 2002; CEI-4,561 MW on August 1, 2002; TE-2,104 MW on July 3, 2002; JCP&L-5,802 MW on August 2, 2002; Met-Ed-2,616 MW on August 14, 2002; and Penelec-2,693 MW on July 29, 2002. JCP&L's load was auctioned off in the New 13 Jersey BGS Auction, transferring the full 5,100 MW load obligation to otherauction and won a segment of that load. Based on existing capacity plans, ongoing arrangements for firm purchase contracts, and anticipated term power sales and purchases, FirstEnergy has sufficient supply resources to meet load obligations. The current FirstEnergy capacity portfolio contains 13,387 MW of owned generation and approximately 1,600 MW of long-term purchases from non-utility generators. Any remaining load obligations will be met through a mix of multi-year forward purchases, short-term forward purchases (less than one year) and spot market purchases. Regional Reliability The Companies participate with 24 other electric companies operating in nine states in ECAR, which was organized for the purpose of furthering the reliability of bulk power supply in the area through coordination of the planning and operation by the ECAR members of their bulk power supply facilities. The ECAR members have established principles and procedures regarding matters affecting the reliability of the bulk power supply within the ECAR region. Procedures have been adopted regarding: i) the evaluation and simulated testing of systems' performance; ii) the establishment of minimum levels of daily operating reserves; iii) the development of a program regarding emergency procedures during conditions of declining system frequency; and iv) the basis for uniform rating of generating equipment. Following the FirstEnergy/GPU merger the transmission facilities of JCP&L, Met-Ed and Penelec continue to be operated by PJM. PJM is the organization responsible for the operation and control of the bulk electric power system throughout major portions of five Mid-Atlantic states and the District of Columbia. PJM is dedicated to meeting the reliability criteria and standards of the North American Electric Reliability Council and the Mid-Atlantic Area Council. Competition The Companies traditionally competed with other utilities for intersystem bulk power sales and for sales to municipalities and cooperatives. The Companies compete with suppliers of natural gas and other forms of energy in connection with their industrial and commercial sales and in the home climate control market, both with respect to new customers and conversions, and with all other suppliers of electricity. To date, there has been no substantial cogeneration by the Companies' customers. As a result of the actions taken by state legislative bodies over the last few years, major changes in the electric utility business are occurring in parts of the United States, including Ohio, New Jersey and Pennsylvania where FirstEnergy's utility subsidiaries operate. These changes have resulted in fundamental alterations in the way traditional integrated utilities and holding company systems, like FirstEnergy, conduct their business. In accordance with the Ohio electric utility restructuring law under which Ohio electric customers could begin choosing their electric generation suppliers starting in January 2001, FirstEnergy has further aligned its business units to accommodate its retail strategy and participate in the competitive electricity marketplace in Ohio. The organizational changes deal with the unbundling of electric utility services and new ways of conducting business. Sales of electricity in deregulated markets are diversifying FirstEnergy's revenue sources through its competitive subsidiaries in areas outside of the Companies' franchise areas. This strategy has positioned FirstEnergy to compete in the northeast quadrant of the United States - the region targeted by FirstEnergy for growth. FirstEnergy's competitive subsidiaries are actively participating in deregulated energy markets in Ohio, Pennsylvania, New Jersey, Delaware, Maryland and Michigan. Currently, FES is providing electric generation service to customers within those states. As additional states within the northeast region of the United States become deregulated, FES is preparing to enter these markets. Competition in Ohio's electric generation began on January 1, 2001. FirstEnergy moved the operation of the generation portion of its business to its competitive business unit as reflected in its approved Ohio transition plan. The Companies continue to provide generation services to regulated franchise customers who have not chosen an alternative, competitive generation supplier, except in New Jersey where JCP&L's obligation to provide BGS has been removed through a transitional mechanism of auctioning the obligation (see "NJBPU Rate Matters"). In September 2002, Met-Ed and Penelec assigned their PLR responsibility to FES through a wholesale power sale agreement. Under the agreement terms, FES assumes the supply obligation and the energy supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The agreement is automatically extended on an annual basis unless any party elects to cancel the agreement by November 1 of the preceding year (see "PPUC Rate Matters" for further discussion). The Ohio Companies and Penn obtain their generation through power supply agreements with FES. In addition to electric generation, FES is also competing in deregulated natural gas markets as well as offering other energy-related products and services. 14 Research and Development The Companies participate in funding the Electric Power Research Institute (EPRI), which was formed for the purpose of expanding electric research and development under the voluntary sponsorship of the nation's electric utility industry - public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The major portion of EPRI research and development projects is directed toward practical solutions and their applications to problems currently facing the electric utility industry. In 2002, approximately 69% of the Companies' research and development expenditures were related to EPRI. Executive Officers The executive officers are elected at the annual organization meeting of the Board of Directors, held immediately after the annual meeting of stockholders, and hold office until the next such organization meeting, unless the Board of Directors shall otherwise determine, or unless a resignation is submitted.
Position Held During Name Age Past Five Years Dates ----------------- --- -------------------------------------------------------------- -------------------- H. P. Burg 56 Chairman of the Board and Chief Executive Officer 2002-present Vice Chairman of the Board and Chief Executive Officer 2001-2002 Chairman of the Board and Chief Executive Officer 2000-2001 President and Chief Executive Officer 1999-2000 President and Chief Operating Officer 1998-1999 President and Chief Financial Officer *-1998 A. J. Alexander 51 President and Chief Operating Officer 2001-present President 2000-2001 Executive Vice President and General Counsel *-2000 A. R. Garfield 64 President - FirstEnergy Solutions 2001-present Senior Vice President - Supply and Sales 2000-2001 Vice President - Business Development *-2000 R. F. Saunders 59 President and Chief Nuclear Officer - FENOC 2000-present Vice President, Nuclear Site Operations - Pennsylvania Power & Light 1998-2000 Vice President, Nuclear Engineering - Virginia Power Company *-1998 E. T. Carey 60 Senior Vice President 2001-present Vice President - Distribution *-2001 K. J. Keough 43 Senior Vice President 2001-present Vice President - Business Planning & Ventures 1999-2001 Partner - McKinsey & Company *-1999 R. H. Marsh 52 Senior Vice President and Chief Financial Officer 2001-present Vice President and Chief Financial Officer 1998-2001 Vice President - Finance *-1998 C. B. Snyder 57 Senior Vice President 2001-present Executive Vice President - Corporate Affairs - GPU 1998-2001 Senior Vice President - Corporate Affairs - GPU *-1998 L. L. Vespoli 43 Senior Vice President and General Counsel 2001-present Vice President and General Counsel 2000-2001 Associate General Counsel *-2000 H. L. Wagner 50 Vice President, Controller and Chief Accounting Officer 2001-present Controller *-2001 Mrs. Vespoli and Messrs. Burg, Carey, Marsh and Wagner are the executive officers, as noted above, of OE, Penn, CEI, TE, Met-Ed and Penelec. Mrs. Vespoli and Messrs. Carey, Marsh and Wagner are the executive officers of JCP&L. * Indicates position held at least since January 1, 1998.
FirstEnergy Website Each of the registrant's annual report on Form 10-K, quarterly reports on Form 10-K, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy's internet website at www.firstenergycorp.com. These reports are posted on the website as soon as reasonably practicable after they are electronically filed with the SEC. 15 As of January 1, 2003, FirstEnergy's nonutility subsidiaries and the Companies had a total of 17,560 employees located in the United States as follows: FirstEnergy-1,744, OE-1,368, CEI-974, TE-508, Penn-201, JCP&L-39, Met-Ed-61, ATSI-29, FES-2,072, FENOC-2,850, FSG-3,317, MARBEL-32 and GPUS-4,365 (primarily employees supporting JCP&L, Met-Ed and Penelec). ITEM 6. SELECTED FINANCIAL DATA ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required for items 6 through 8 is incorporated herein by reference to Selected Financial Data, Management's Discussion and Analysis of Results of Operations and Financial Condition and Financial Statements included on the pages shown in the following table in FirstEnergy's 2002 Annual Report to Stockholders, as revised (Exhibit 13 below). Item 6 Item 7 Item 8 ------ ------ ------ FirstEnergy.............. 4 5-28 29-66 ITEM 14. CONTROLS AND PROCEDURES (a) Evaluation of Disclosure Controls and Procedures The respective registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and 15d-14(c), as of a date within 90 days prior to the filing date of this report (Evaluation Date). Based on that evaluation those officers have concluded that the registrant's disclosure controls and procedures are effective and were designed to bring to their attention, during the period in which this annual report was being prepared, material information relating to the registrant and its consolidated subsidiaries by others within those entities. (b) Changes in Internal Controls There have been no significant changes in internal controls or in other factors that could significantly affect those controls subsequent to the Evaluation Date. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. Financial Statements Included in Part II of this report and incorporated herein by reference to FirstEnergy's 2002 Annual Report to Stockholders, as revised (Exhibit 13 below), at the pages indicated. First- Energy ------ Report of Independent Accountants....................................... 2 Statements of Income-Three Years Ended December 31, 2002 29 Balance Sheets-December 31, 2002 and 2001............................... 30 Statements of Capitalization-December 31, 2002 and 2001. 31-34 Statements of Common Stockholders' Equity-Three Years Ended December 31, 2002............................................... 35 Statements of Preferred Stock-Three Years Ended December 31, 2002....... 36 Statements of Cash Flows-Three Years Ended December 31, 2002............ 37 Statements of Taxes-Three Years Ended December 31, 2002................. 38 Notes to Financial Statements........................................... 39-66 16 3. Exhibits - FirstEnergy Exhibit Number ------ 3-1 -- Articles of Incorporation constituting FirstEnergy Corp.'s Articles of Incorporation, dated September 17, 1996. (September 17, 1996 Form 8-K, Exhibit C) 3-1(a) -- Amended Articles of Incorporation of FirstEnergy Corp. (Registration No. 333-21011, Exhibit (3)-1) 3-2 -- Regulations of FirstEnergy Corp. (September 17, 1996 Form 8-K, Exhibit D) 3-2(a) -- FirstEnergy Corp. Amended Code of Regulations. Registration No. 333-21011, Exhibit (3)-2) 4-1 -- Rights Agreement (December 1, 1997 Form 8-K, Exhibit 4.1) 4-2 -- FirstEnergy Corp. to The Bank of New York, Supplemental Indenture, dated November 7, 2001. (2001 Form 10-K, Exhibit 4-2) 10-1 -- FirstEnergy Corp. Executive and Director Incentive Compensation Plan, revised November 15, 1999. (1999 Form 10-K, Exhibit 10-1) 10-2 -- Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, revised November 15, 1999. (1999 Form 10-K, Exhibit 10-2) 10-3 -- Employment, severance and change of control agreement between FirstEnergy Corp. and executive officers. (1999 Form 10-K, Exhibit 10-3) 10-4 -- FirstEnergy Corp. Supplemental Executive Retirement Plan, amended January 1, 1999. (1999 Form 10-K, Exhibit 10-4) 10-5 -- FirstEnergy Corp. Executive Incentive Compensation Plan. (1999 Form 10-K, Exhibit 10-5) 10-6 -- Restricted stock agreement between FirstEnergy Corp. and A. J. Alexander. (1999 Form 10-K, Exhibit 10-6) 10-7 -- FirstEnergy Corp. Executive and Director Incentive Compensation Plan. (1998 Form 10-K, Exhibit 10-1) 10-8 -- Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, amended February 15, 1999. (1998 Form 10-K, Exhibit 10-2) 10-9 -- Restricted stock agreement between FirstEnergy Corp. and A. J. Alexander. (2000 Form 10-K, Exhibit 10-9) 10-10 -- Restricted stock agreement between FirstEnergy Corp. and H. P. Burg. (2000 Form 10-K, Exhibit 10-10) 10-11 -- Stock option agreement between FirstEnergy Corp. and officers dated November 22, 2000. (2000 Form 10-K, Exhibit 10-11) 10-12 -- Stock option agreement between FirstEnergy Corp. and officers dated March 1, 2000. (2000 Form 10-K, Exhibit 10-12) 10-13 -- Stock option agreement between FirstEnergy Corp. and director dated January 1, 2000. (2000 Form 10-K, Exhibit 10-13) 10-14 -- Stock option agreement between FirstEnergy Corp. and two directors dated January 1, 2001. (2000 Form 10-K, Exhibit 10-14) 10-15 -- Executive and Director Incentive Compensation Plan dated May 15, 2001. (2001 Form 10-K, Exhibit 10-15) 17 10-16 -- Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, revised September 18, 2000. (2001 Form 10-K, Exhibit 10-16) 10-17 -- Stock Option Agreements between FirstEnergy Corp. and Officers dated May 16, 2001. (2001 Form 10-K, Exhibit 10-17) 10-18 -- Restricted Stock Agreements between FirstEnergy Corp. and Officers dated February 20, 2002. (2001 Form 10-K, Exhibit 10-18) 10-19 -- Stock Option Agreements between FirstEnergy Corp. and One Director dated January 1, 2002. (2001 Form 10-K, Exhibit 10-19) 10-20 -- FirstEnergy Corp. Executive Deferred Compensation Plan. (2001 Form 10-K, Exhibit 10-20) 10-21 -- Executive Incentive Compensation Plan-Tier 2. (2001 Form 10-K, Exhibit 20-21) 10-22 -- Executive Incentive Compensation Plan-Tier 3. (2001 Form 10-K, Exhibit 20-22) 10-23 -- Executive Incentive Compensation Plan-Tier 4. (2001 Form 10-K, Exhibit 10-23) 10-24 -- Executive Incentive Compensation Plan-Tier 5. (2001 Form 10-K, Exhibit 10-24) 10-25 -- Amendment to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, effective April 5, 2001. (2001 Form 10-K, Exhibit 10-25) 10-26 -- Form of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration Plan for Outside Directors of GPU, Inc., and Retirement Plan for Outside Directors of GPU, Inc. (2001 Form 10-K, Exhibit 10-26) 10-27 -- GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (2001 Form 10-K, Exhibit 10-27) 10-28 -- Executive and Director Stock Option Agreement dated June 11, 2002. 10-29 -- Director Stock Option Agreement. 10-30 -- Executive and Director Executive Incentive Compensation Plan, Amendment dated May 21, 2002. 10-31 -- Directors Deferred Compensation Plan, Revised Nov. 19, 2002. 10-32 -- Executive Incentive Compensation Plan 2002. 10-33 -- GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries as amended and restated to reflect amendments through June 3, 1999. (1999 Form 10-K, Exhibit 10-V, File No. 1-6047, GPU, Inc.) 10-34 -- Form of 1998 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1997 Form 10-K, Exhibit 10-Q, File No. 1-6047, GPU, Inc.) 10-35 -- Form of 1999 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1999 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.) 10-36 -- Form of 2000 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (2000 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.) 10-37 -- Deferred Remuneration Plan for Outside Directors of GPU, Inc. as amended and restated effective August 8, 2000. (2000 Form 10-K, Exhibit 10-O, File No. 1-6047, GPU, Inc.) 10-38 -- Retirement Plan for Outside Directors of GPU, Inc. as amended and restated as of August 8, 2000. (2000 Form 10-K, Exhibit 10-N, File No. 1-6047, GPU, Inc.) 18 10-39 -- Forms of Estate Enhancement Program Agreements entered into by certain former GPU directors. (1999 Form 10-K, Exhibit 10-JJ, File No. 1-6047, GPU, Inc.) * 12.1 -- Consolidated fixed charge ratios. * 13 -- FirstEnergy 2002 Annual Report to Stockholders, as revised. (Only those portions expressly incorporated by reference in this Form 10-K/A are to be deemed "filed" with the SEC.) 21 -- List of Subsidiaries of the Registrant at December 31, 2002. * 23 -- Consent of Independent Accountants. * 99.1 -- Chief Executive Officer Certification * 99.2 -- Chief Financial Officer Certification * Indicates revised exhibits included in this From 10-K/A in electronic format. Reference is made to the original 10-K for the other exhibits filed with it. (b) Reports on Form 8-K FirstEnergy- FirstEnergy filed fourteen reports on Form 8-K since September 30, 2002. A report dated October 7, 2002 reported updated cost and schedule estimates associated with efforts to return Davis-Besse Nuclear Power Station to service. A report dated October 31, 2002 reported updated information associated with Davis-Besse restoration efforts. A report dated December 2, 2002 reported the merger of the GPU Employees Savings Plan into the FirstEnergy System Savings Plan. A report dated December 3, 2002 reported updated FirstEnergy 2003 earnings guidance. A report dated December 20, 2002 reported that FirstEnergy subsidiaries would retain ownership of four power plants previously planned to be sold. A report dated January 17, 2003 reported updated information related with efforts to prepare Davis-Besse for a safe and reliable return to service and the updated schedule for JCP&L rate proceedings. A report dated January 21, 2003 reported that the Pennsylvania Supreme Court denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the Pennsylvania Public Utility Commission's order approving the FirstEnergy and GPU merger, let stand the Commonwealth Court's denial of PLR relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. A report dated March 11, 2003 reported updated Davis-Besse information including the installation of the new reactor head on the reactor vessel. A report dated March 17, 2003 reported updated Davis-Besse information, the filing of a $2 billion shelf registration with the SEC and the status of the JCP&L rate proceedings. A report dated March 18, 2003 reported NJBPU audit results of JCP&L restructuring-related deferrals. A report dated April 16, 2003 reported updated Davis-Besse information. A report dated April 18, 2003 reported FirstEnergy's divestiture of its Argentina operations through the abandonment of its investment resulting in a second quarter 2003 charge to net income of $63 million. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003 results and other updated information including Davis-Besse updated ready for restart schedule. A report dated May 9, 2003 reported updated Davis-Besse information and a JCP&L rate proceedings update. 19 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. FIRSTENERGY CORP. /s/Harvey L. Wagner --------------------------------------- Harvey L. Wagner Vice President, Controller and Chief Accounting Officer Date: May 9, 2003 20 Certification I, H. Peter Burg, certify that: 1. I have reviewed this amended annual report on Form 10-K/A of FirstEnergy Corp; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 9, 2003 /s/H. Peter Burg H. Peter Burg ------------------------- Chief Executive Officer 21 Certification I, Richard H. Marsh, certify that: 1. I have reviewed this amended annual report on Form 10-K/A of FirstEnergy Corp. 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 9, 2003 /s/Richard H. Marsh ---------------------------------- Richard H. Marsh Chief Financial Officer 22