-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, P7ec+5MPJiaH35PjRNNJXLvKH5UWiZE+Vu742VhbGaGnjcPwnAObK9adZRx9/EGK A9hkDIVrqXLzPgaxEGrwZw== 0001031296-03-000070.txt : 20030326 0001031296-03-000070.hdr.sgml : 20030325 20030326152619 ACCESSION NUMBER: 0001031296-03-000070 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 40 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030326 FILER: COMPANY DATA: COMPANY CONFORMED NAME: TOLEDO EDISON CO CENTRAL INDEX KEY: 0000352049 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 344375005 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03583 FILM NUMBER: 03618214 BUSINESS ADDRESS: STREET 1: 76 SOUTH MAIN STREET CITY: AKRON STATE: OH ZIP: 43308 BUSINESS PHONE: 2166229800 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CLEVELAND ELECTRIC ILLUMINATING CO CENTRAL INDEX KEY: 0000020947 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 340150020 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-02323 FILM NUMBER: 03618215 BUSINESS ADDRESS: STREET 1: 76 SOUTH MAIN STREET STREET 2: C/O FIRSTENERGY CORP CITY: AKRON STATE: OH ZIP: 44308 BUSINESS PHONE: 2166229800 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PENNSYLVANIA POWER CO CENTRAL INDEX KEY: 0000077278 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 250718810 STATE OF INCORPORATION: PA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03491 FILM NUMBER: 03618216 BUSINESS ADDRESS: STREET 1: 1 E WASHINGTON ST STREET 2: P O BOX 891 CITY: NEW CASTLE STATE: PA ZIP: 16103-0891 BUSINESS PHONE: 4126525531 FILER: COMPANY DATA: COMPANY CONFORMED NAME: OHIO EDISON CO CENTRAL INDEX KEY: 0000073960 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 340437786 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-02578 FILM NUMBER: 03618218 BUSINESS ADDRESS: STREET 1: 76 S MAIN ST CITY: AKRON STATE: OH ZIP: 44308 BUSINESS PHONE: 2163845100 FILER: COMPANY DATA: COMPANY CONFORMED NAME: FIRSTENERGY CORP CENTRAL INDEX KEY: 0001031296 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 341843785 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 333-21011 FILM NUMBER: 03618213 BUSINESS ADDRESS: STREET 1: 76 SOUTH MAIN ST CITY: AKRON STATE: OH ZIP: 44308-1890 BUSINESS PHONE: 3303845100 MAIL ADDRESS: STREET 1: 76 SOUTH MAIN ST CITY: AKRON STATE: OH ZIP: 44308-1890 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PENNSYLVANIA ELECTRIC CO CENTRAL INDEX KEY: 0000077227 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 250718085 STATE OF INCORPORATION: PA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03522 FILM NUMBER: 03618217 BUSINESS ADDRESS: STREET 1: 2800 POTTSVILLE PIKE READING STREET 2: MUHLENBERG TOWNSHIP CITY: BERKS COUNTY STATE: PA ZIP: 19640-0001 BUSINESS PHONE: 6109293601 MAIL ADDRESS: STREET 1: C/O GPU ENERGY STREET 2: 2800 POTTSVILLE PIKE CITY: READING STATE: PA ZIP: 19605-2459 FILER: COMPANY DATA: COMPANY CONFORMED NAME: METROPOLITAN EDISON CO CENTRAL INDEX KEY: 0000065350 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 230870160 STATE OF INCORPORATION: PA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-00446 FILM NUMBER: 03618219 BUSINESS ADDRESS: STREET 1: 2800 POTTSVILLE PIKE STREET 2: MUHLENBERG TOWNSHIP CITY: READING STATE: PA ZIP: 19640-0001 BUSINESS PHONE: 6109293601 MAIL ADDRESS: STREET 1: C/O ENERGY GPU ENERGY STREET 2: 2800 POTTERVILLE CITY: READING STATE: PA ZIP: 19640-0001 FILER: COMPANY DATA: COMPANY CONFORMED NAME: JERSEY CENTRAL POWER & LIGHT CO CENTRAL INDEX KEY: 0000053456 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 210485010 STATE OF INCORPORATION: NJ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03141 FILM NUMBER: 03618220 BUSINESS ADDRESS: STREET 1: 2800 POTTSVILLE PIKE CITY: READING STATE: PA ZIP: 19640-0001 BUSINESS PHONE: 6109293601 MAIL ADDRESS: STREET 1: C/O GPU ENERGY STREET 2: 2800 POTTSVILLE PIKE CITY: READING STATE: PA ZIP: 19640-0001 10-K 1 fe_10k.txt FORM 10K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K (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 1-2578 OHIO EDISON COMPANY 34-0437786 (An Ohio Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 34-0150020 (An Ohio Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3583 THE TOLEDO EDISON COMPANY 34-4375005 (An Ohio Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3491 PENNSYLVANIA POWER COMPANY 25-0718810 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3141 JERSEY CENTRAL POWER & LIGHT COMPANY 21-0485010 (A New Jersey Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-446 METROPOLITAN EDISON COMPANY 23-0870160 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3522 PENNSYLVANIA ELECTRIC COMPANY 25-0718085 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 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 Ohio Edison Company Cumulative Preferred Stock, $100 par value: 3.90% Series All series registered on New 4.40% Series York Stock Exchange and 4.44% Series Chicago Stock Exchange 4.56% Series The Cleveland Electric Cumulative Serial Preferred Stock, without Illuminating Company par value: $7.40 Series A Both series registered on New Adjustable Rate, Series L York Stock Exchange The Toledo Edison Cumulative Preferred Stock, par value Company $100 per share: 4.25% Series American Stock Exchange Cumulative Preferred Stock, par value $25 per share: $2.365 Series All series registered on Adjustable Rate, Series A New York Stock Exchange Adjustable Rate, Series B First Mortgage Bonds: 8% Series due 2003 New York Stock Exchange Pennsylvania Power Cumulative Preferred Stock, $100 Company par value: 4.24% Series All series registered on 4.25% Series Philadelphia Stock Exchange, 4.64% Series Inc. Jersey Central Power & Cumulative Preferred Stock, without Light Company par value: 4% Series 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; and for all other registrants, none. Indicate the number of shares outstanding of each 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 Ohio Edison Company, no par value 100 The Cleveland Electric Illuminating Company, no par value 79,590,689 The Toledo Edison Company, $5 par value 39,133,887 Pennsylvania Power Company, $30 par value 6,290,000 Jersey Central Power & Light Company, $10 par value 15,371,270 Metropolitan Edison Company, no par value 859,500 Pennsylvania Electric Company, $20 par value 5,290,596 FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company common stock; Ohio Edison Company is the sole holder of Pennsylvania Power Company common stock. 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 (Pages 6-53) Part II Proxy Statement for 2003 Annual Meeting of Stockholders to be held May 20, 2003 Part III
This combined Form 10-K is separately filed by FirstEnergy Corp., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the seven FirstEnergy subsidiary registrants is also attributed to FirstEnergy. 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................................... 6 Capital Requirements...................................... 7 Met-Ed Capital Trust and Penelec Capital Trust............ 8 Nuclear Regulation........................................ 9 Nuclear Insurance.........................................10 Environmental Matters.....................................10 Air Regulation..........................................10 Water Regulation........................................11 Waste Disposal..........................................11 Summary.................................................12 Fuel Supply...............................................12 System Capacity and Reserves..............................13 Regional Reliability......................................13 Competition...............................................14 Research and Development..................................14 Executive Officers........................................15 FirstEnergy Website.......................................15 Item 2. Properties..................................................16 Item 3. Legal Proceedings...........................................17 Item 4. Submission of Matters to a Vote of Security Holders................................................. 17 Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters..................................... 17 Item 6. Selected Financial Data.................................. 17 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........... 17 Item 8. Financial Statements and Supplementary Data.............. 17 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure..................... 18 Part III Item 10. Directors and Executive Officers of the Registrant....... 18 Item 11. Executive Compensation................................... 18 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters............... 18 Item 13. Certain Relationships and Related Transactions........... 18 Item 14. Controls and Procedures.................................. 18 Part IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K..................................... 19 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. 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 were $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 equity interest. FirstEnergy and Aquila together own all of the outstanding shares of Avon through a jointly owned subsidiary, with each company having a 50-percent voting interest. Originally, in accordance with the accounting guidance described above, the earnings of those foreign operations were not recognized in current earnings from the date of the GPU acquisition until February 6, 2002, the date when Aquila began discussions to revise its initial offer to purchase Avon. However, the revision to the initial offer by Aquila caused a reversal of that accounting in the first quarter of 2002, resulting in the recognition of a cumulative effect of a change in accounting which increased net income by $31.7 million, or $0.11 per share of common stock, recognizing the net income of Avon from November 7, 2001 to February 6, 2002 that previously was not recognized by FirstEnergy in its consolidated earnings. This resulted from the application of guidance provided by 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," and accounting under EITF Issue No. 87-11. In the fourth quarter of 2002, FirstEnergy recorded a $50 million charge ($32.5 million net of tax), or $0.11 per share of common stock, 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 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. As a result, under EITF Issue No. 90-6, FirstEnergy recorded in the fourth quarter a non-cash cumulative effect of accounting change on its 2002 Consolidated Statement of Income related to Emdersa's cumulative results of operations from November 7, 2001 through October 31, 2002. The amount of this after-tax charge was $88.8 million, or $0.30 per share of common stock (comprised of $104.1 million in currency transaction losses arising principally from U.S. dollar denominated debt, offset by $15.3 million of operating income). On November 1, 2002, FirstEnergy began consolidating the results of Emdersa's operations in its financial statements. In addition to the currency transaction losses of $104.1 million, FirstEnergy recognized a currency translation adjustment in other comprehensive income 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). 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. 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 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. JCP&L will have an opportunity to conduct discovery on the report, cross-examine the auditors and submit rebuttal testimony. The Administrative Law Judge's recommended decision is due in June 2003 and the NJBPU's subsequent decision is due in July 2003. 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. 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 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. 2002 Capital Expenditures Forecast --------------------------------------- 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 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. 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. 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. 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's current schedule projects having the plant available for restart in April 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 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 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 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: Coal 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 Jersey BGS Auction, transferring the full 5,100 MW load obligation to other parties for the period August 1, 2002 to July 31, 2003. FES participated in the auction 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. 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. 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 2. PROPERTIES The Companies' respective first mortgage indentures constitute, in the opinion of the Companies' counsel, direct first liens on substantially all of the respective Companies' physical property, subject only to excepted encumbrances, as defined in the indentures. See "Leases" and "Capitalization" notes to the respective financial statements for information concerning leases and financing encumbrances affecting certain of the Companies' properties. The Companies own, individually or together as tenants in common, and/or lease, the generating units in service as of March 1, 2003, shown on the table below.
Net Demonstrated Capacity (MW) ------------- OE Penn CEI TE -------------- ----------- ------------ ------------- Unit Total % MW % MW % MW % MW ---- ----- - -- - -- - -- - --- Plant - Location - ---------------- Coal-Fired Units Ashtabula-.................. 5 244 -- -- -- -- 100.00% 244 -- -- Ashtabula, OH Bay Shore-.................. 1-4 631 -- -- -- -- -- -- 100.00% 631 Toledo, OH R. E. Burger-............... 3-5 406 100.00% 406 -- -- -- -- -- -- Shadyside, OH Eastlake-Eastlake, OH....... 1-5 1,233 -- -- -- -- 100.00% 1,233 -- -- Lakeshore-.................. 18 245 -- -- -- -- 100.00% 245 -- -- Cleveland, OH Bruce Mansfield-............ 1 780 60.00% 468 33.50% 261 6.50% 51 -- -- Shippingport, PA......... 2 780 43.06% 336 9.36% 73 30.28%(a) 236 17.30%(a) 135 3 800 49.34% 395 6.28% 50 24.47% 196 19.91% 159 W. H. Sammis-............... 1-6 1,620 100.00% 1,620 -- -- -- -- -- -- Stratton, OH............. 7 600 48.00% 288 20.80% 125 31.20% 187 -- -- ------ ----- ----- ----- ----- Total................. 7,339 3,513 509 2,392 925 ------ ----- ----- ----- ----- Nuclear Units Beaver Valley-.............. 1 821 35.00% 287 65.00% 534 -- -- -- -- Shippingport, PA......... 2 831 41.88%(b) 348 13.74% 114 24.47% 203 19.91%(c) 166 Davis-Besse-................ 1 883 -- -- -- -- 51.38% 454 48.62% 429 Oak Harbor, OH Perry-...................... 1 1,260 30.00%(b) 378 5.24% 66 44.85% 565 19.91% 251 N. Perry Village, OH. ------ ------ ----- ----- ----- Total................. 3,795 1,013 714 1,222 846 ------ ----- ----- ----- ----- Oil/Gas-Fired/ Pumped Storage Units Richland-Defiance, OH....... 1-6 432 -- -- -- -- -- -- 100.00% 432 Seneca-Warren, PA........... 1-3 435 -- -- -- -- 100.00% 435 -- -- Sumpter- Sumpter Twp., MI... 1-4 340 -- -- -- -- -- -- 100.00% 340 West Lorain................. 1-6 545 100.00% 545 -- -- -- -- -- -- Lorain, OH Yard's Creek-Blairstown Twp., NJ................. 1-3 200 -- -- -- -- -- -- -- Other....................... 301 109 19 33 35 ------ ----- ----- ----- ----- Total................. 2,253 654 19 468 807 ------ ----- ----- ----- ----- Total................. 13,387 5,180 1,242 4,082 2,578 ====== ===== ===== ===== ===== JCP&L Met-Ed ---------- ---------- % MW % MW - -- - -- Plant - Location - ---------------- Coal-Fired Units Ashtabula-.................. -- -- -- -- Ashtabula, OH Bay Shore-.................. -- -- -- -- Toledo, OH R. E. Burger-............... -- -- -- -- Shadyside, OH Eastlake-Eastlake, OH....... -- -- -- -- Lakeshore-.................. -- -- -- -- Cleveland, OH Bruce Mansfield-............ -- -- -- -- Shippingport, PA......... -- -- -- -- -- -- -- -- W. H. Sammis-............... -- -- -- -- Stratton, OH............. -- -- -- -- ---- ---- Total................. -- -- ---- ---- Nuclear Units Beaver Valley-.............. -- -- -- -- Shippingport, PA......... -- -- -- -- Davis-Besse-................ -- -- -- -- Oak Harbor, OH Perry-...................... -- -- -- -- N. Perry Village, OH. ---- ---- Total................. -- -- ---- ---- Oil/Gas-Fired/ Pumped Storage Units Richland-Defiance, OH....... -- -- -- -- Seneca-Warren, PA........... -- -- -- -- Sumpter- Sumpter Twp., MI... -- -- -- -- West Lorain................. -- -- -- -- Lorain, OH Yard's Creek-Blairstown Twp., NJ................. 50% 200 -- -- Other....................... 86 19 ---- ---- Total................. 286 19 ---- ---- Total................. 286 19 ==== ==== Notes: (a) CEI's interests consist of 1.68% owned and 28.60% leased and TE's interests are leased. (b) OE's interests consist of 20.22% owned and 21.66% leased for Beaver Valley Unit 2; and 17.42% owned (representing portion leased from a wholly owned subsidiary of OE) and 12.58% leased for Perry. (c) TE's interests consist of 1.65% owned and 18.26% leased.
Prolonged outages of existing generating units might make it necessary for the Companies, depending upon the demand for electric service upon their system, to use to a greater extent than otherwise, less efficient and less economic generating units, or purchased power, and in some cases may require the reduction of load during peak periods under the Companies' interruptible programs, all to an extent not presently determinable. The Companies' generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 345 kV. The Companies' overhead and underground transmission lines aggregate 14,941 pole miles. The Companies' electric distribution systems include 111,704 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of 86,334,000 kilovolt-amperes. FirstEnergy's transmission facilities that are owned and operated by ATSI also interconnect with those of AEP, DPL, Duquesne, Allegheny, MEC and Penelec. The transmission facilities of JCP&L, Met-Ed and Penelec are physically interconnected and are operated on an integrated basis as part of the PJM RTO. FirstEnergy's distribution and transmission systems as of December 31, 2002, consist of the following: Substation Distribution Transmission Transformer Lines Lines Capacity ------------ ------------ ----------- (Miles) (kV-amperes) OE.................... 28,879 550 8,232,000 Penn.................. 5,476 44 1,712,000 CEI................... 24,662 2,144 9,381,000 TE.................... 1,255 223 3,596,000 JCP&L................. 17,278 2,106 18,371,000 Met-Ed................ 14,745 1,407 9,937,000 Penelec............... 19,409 2,689 13,159,000 ATSI.................. -- 5,778 22,369,000 ------- ------ ---------- Total................. 111,704 14,941 86,757,000 FirstEnergy's MARBEL Energy subsidiary owns interests in crude oil and natural gas production, as well as natural gas distribution and transmission facilities. MARBEL's subsidiaries include Marbel HoldCo, Inc. a holding company which has a 50% ownership in Great Lakes Energy Partners, LLC, an oil and natural gas exploration and production venture and Northeast Ohio Operating Companies, Inc. which has as a subsidiary, Northeast Ohio Natural Gas Corporation. The joint venture in Great Lakes includes interests in more than 7,700 oil and natural gas wells, drilling rights to nearly one million acres, proved reserves of 450 billion cubic feet equivalent of natural gas and oil and 5,000 miles of pipelines in the Appalachian Basin. ITEM 3. LEGAL PROCEEDINGS Reference is made to Note 7, Commitments, Guarantees and Contingencies, of the Notes to Consolidated Financial Statements contained in Item 8 for a description of certain legal proceedings involving FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The information required by this item for FirstEnergy is included on page 7 of FirstEnergy's 2002 Annual Report to Stockholders (Exhibit 13). The information required for OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec is not applicable because they are wholly owned subsidiaries. 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 the respective company's 2002 Annual Report to Stockholders (Exhibit 13). Item 6 Item 7 Item 8 ------ ------ ------ FirstEnergy.............. 7 8-24 25-53 OE....................... 1 2-11 12-32 Penn..................... 1 2-10 11-27 CEI...................... 1 2-12 13-33 TE....................... 1 2-12 13-33 JCP&L.................... 1 2-11 12-30 Met-Ed................... 1 2-11 12-30 Penelec.................. 1 2-11 12-30 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE On April 11, 2002, FirstEnergy dismissed Arthur Andersen LLP as the independent accountant for FirstEnergy Corp. and its wholly owned subsidiaries, OE, Penn, CEI, TE, JCP&L, Met-Ed and Penelec (Registrants) effective with the completion of the 2001 audits and related regulatory filings. Also, on April 11, 2002, each of those companies appointed PricewaterhouseCoopers LLP as their new independent accountant effective for the first quarter of 2002. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT FirstEnergy ----------- The information required by Item 10, with respect to Identification of FirstEnergy's Directors and with respect to reports required to be filed under Section 16 of the Securities Exchange Act of 1934, is incorporated herein by reference to FirstEnergy's 2003 Proxy Statement filed with the SEC pursuant to Regulation 14A and, with respect to Identification of Executive Officers, to "Part I, Item 1. Business - Executive Officers" herein. OE, Penn, CEI, TE, JCP&L, Met-Ed and Penelec -------------------------------------------- H. P. Burg, A. J. Alexander and R. H. Marsh are the Directors of OE, Penn, CEI, TE, Met-Ed and Penelec. Information concerning these individuals is shown in the "Executive Officers" section of Item 1. E. T. Carey, C. E. Jones, L. L. Vespoli, G. E. Persson and S. C. Van Ness are the Directors of JCP&L. Mr. Jones has served as FirstEnergy's Vice President-Regional Operations since 2001. From 1998-2001, Mr. Jones served as President of FirstEnergy's Northern Region; in 1998 he served as Manager of the Northern Region. Mrs. Persson has served in the New Jersey Division of Consumer Affairs Elder Fraud Investigation Unit since 1999. She previously served as liaison (Special Assistant Director) between the New Jersey Division of Consumer Affairs and various state boards. Prior to 1995, she was owner and President of Business Dynamics Associates of Red Bank, NJ. Mrs. Persson is a member of the United States Small Business Administration National Advisory Board, the New Jersey Small Business Advisory Council, the Board of Advisors of Brookdale Community College and the Board of Advisors of Georgian Court College. Mr. Van Ness has been Of Counsel in the firm of Hubert, Van Ness, Cayci and Goodell, LP of Princeton, NJ since 1998. Prior to that he was affiliated with the law firm of Pico, Mack, Kennedy, Jaffe, Perrella and Yoskin of Trenton, NJ since 1990. He is also a director of The Prudential Insurance Company of America. Information concerning the other Directors of JCP&L is shown in the "Executive Officers" section of item 1. ITEM 11. EXECUTIVE COMPENSATION ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec - ----------------------------------------------------------- The information required by Items 11, 12 and 13 is incorporated herein by reference to FirstEnergy's 2003 Proxy Statement filed with the SEC pursuant to Regulation 14A. 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 the respective company's 2002 Annual Report to Stockholders (Exhibit 13 below) at the pages indicated.
First- Energy OE Penn CEI TE JCP&L Met-Ed Penelec ------ -- ---- --- -- ----- ------ ------- Report of Independent Accountants....................... 6 33-34 28-29 34-35 34-35 31-32 31-32 31-32 Statements of Income-Three Years Ended December 31, 2002 .................................... 25 12 11 13 13 12 12 12 Balance Sheets-December 31, 2002 and 2001............... 26 13 12 14 14 13 13 13 Statements of Capitalization-December 31, 2002 and 2001. ....................................... 27-30 14-15 13 15-16 15-16 14 14 14 Statements of Common Stockholders' Equity-Three Years Ended December 31, 2002......................... 31 16 14 17 17 15 15 15 Statements of Preferred Stock-Three Years Ended December 31, 2002 .................................... 32 16 14 17 17 15 15 15 Statements of Cash Flows-Three Years Ended December 31, 2002 .................................... 33 17 15 18 18 16 16 16 Statements of Taxes-Three Years Ended December 31, 2002. ................................... 34 18 16 19 19 17 17 17 Notes to Financial Statements........................... 35-53 19-32 17-27 20-33 20-33 18-30 18-30 18-30 2. Financial Statement Schedules Included in Part IV of this report: First- Energy OE Penn CEI TE JCP&L Met-Ed Penelec ------ -- ---- --- -- ----- ------ ------- Report of Independent Accountants....................... 53-54 55-56 61-62 57-58 59-60 63-64 65-66 67-68 Schedule - Three Years Ended December 31, 2002: II - Consolidated Valuation and Qualifying Accounts..... 69 70 73 71 72 74 75 76
Schedules other than the schedule listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto. 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) Exhibit Number - ------ 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) 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) (A) 10-28 -- Executive and Director Stock Option Agreement dated June 11, 2002. (A) 10-29 -- Director Stock Option Agreement. (A) 10-30 -- Executive and Director Executive Incentive Compensation Plan, Amendment dated May 21, 2002. (A) 10-31 -- Directors Deferred Compensation Plan, Revised Nov. 19, 2002. (A) 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.) 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.) (A) 12.1 -- Consolidated fixed charge ratios. (A) 13 -- FirstEnergy 2002 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed "filed" with the SEC.) (A) 21 -- List of Subsidiaries of the Registrant at December 31, 2002. (A) 23 -- Consent of Independent Accountants. (A) 99.1 -- Chief Executive Officer Certification (FirstEnergy, OE, CEI, TE, Penn, Met-Ed and Penelec) (A) 99.2 -- Chief Financial Officer Certification (FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec) (A) Provided herein in electronic format as an exhibit. Exhibit Number - ------- 3. Exhibits - Ohio Edison 2-1 -- Agreement and Plan of Merger, dated as of September 13, 1996, between Ohio Edison Company (OE) and Centerior Energy Corporation. (September 17, 1996 Form 8-K, Exhibit 2-1) 3-1 -- Amended Articles of Incorporation, Effective June 21, 1994, constituting OE's Articles of Incorporation. (1994 Form 10-K, Exhibit 3-1) 3-2 -- Amended and Restated Code of Regulations, amended March 15, 2002. (2001 Form 10-K, Exhibit 3-2) (B) 4-1 -- Indenture dated as of August 1, 1930 between OE and Bankers Trust Company, (now the Bank of New York), as Trustee, as amended and supplemented by Supplemental Indentures: Dated as of File Reference Exhibit No. ----------- -------------- ----------- March 3, 1931 2-1725 B1,B-1(a),B-1(b) November 1, 1935 2-2721 B-4 January 1, 1937 2-3402 B-5 September 1, 1937 Form 8-A B-6 June 13, 1939 2-5462 7(a)-7 August 1, 1974 Form 8-A, August 28, 1974 2(b) July 1, 1976 Form 8-A, July 28, 1976 2(b) December 1, 1976 Form 8-A, December 15, 1976 2(b) June 15, 1977 Form 8-A, June 27, 1977 2(b) Supplemental Indentures: September 1, 1944 2-61146 2(b)(2) April 1, 1945 2-61146 2(b)(2) September 1, 1948 2-61146 2(b)(2) May 1, 1950 2-61146 2(b)(2) January 1, 1954 2-61146 2(b)(2) May 1, 1955 2-61146 2(b)(2) August 1, 1956 2-61146 2(b)(2) March 1, 1958 2-61146 2(b)(2) April 1, 1959 2-61146 2(b)(2) June 1, 1961 2-61146 2(b)(2) September 1, 1969 2-34351 2(b)(2) May 1, 1970 2-37146 2(b)(2) September 1, 1970 2-38172 2(b)(2) June 1, 1971 2-40379 2(b)(2) August 1, 1972 2-44803 2(b)(2) September 1, 1973 2-48867 2(b)(2) May 15, 1978 2-66957 2(b)(4) February 1, 1980 2-66957 2(b)(5) April 15, 1980 2-66957 2(b)(6) June 15, 1980 2-68023 (b)(4)(b)(5) October 1, 1981 2-74059 (4)(d) October 15, 1981 2-75917 (4)(e) February 15, 1982 2-75917 (4)(e) July 1, 1982 2-89360 (4)(d) March 1, 1983 2-89360 (4)(e) March 1, 1984 2-89360 (4)(f) September 15, 1984 2-92918 (4)(d) September 27, 1984 33-2576 (4)(d) November 8, 1984 33-2576 (4)(d) December 1, 1984 33-2576 (4)(d) December 5, 1984 33-2576 (4)(e) January 30, 1985 33-2576 (4)(e) February 25, 1985 33-2576 (4)(e) July 1, 1985 33-2576 (4)(e) October 1, 1985 33-2576 (4)(e) January 15, 1986 33-8791 (4)(d) May 20, 1986 33-8791 (4)(d) Dated as of File Reference Exhibit No ----------- -------------- ---------- June 3, 1986 33-8791 (4)(e) October 1, 1986 33-29827 (4)(d) August 25, 1989 33-34663 (4)(d) February 15, 1991 33-39713 (4)(d) May 1, 1991 33-45751 (4)(d) May 15, 1991 33-45751 (4)(d) September 15, 1991 33-45751 (4)(d) April 1, 1992 33-48931 (4)(d) June 15, 1992 33-48931 (4)(d) September 15, 1992 33-48931 (4)(e) April 1, 1993 33-51139 (4)(d) June 15, 1993 33-51139 (4)(d) September 15, 1993 33-51139 (4)(d) November 15, 1993 1-2578 (4)(2) April 1, 1995 1-2578 (4)(2) May 1, 1995 1-2578 (4)(2) July 1, 1995 1-2578 (4)(2) June 1, 1997 1-2578 (4)(2) April 1, 1998 1-2578 (4)(2) June 1, 1998 1-2578 (4)(2) September 29, 1999 1-2578 (4)(2) April 1, 2000 1-2578 (4)(2)(a) April 1, 2000 1-2578 (4)(2)(b) June 1, 2001 1-2578 (B) 4-2 -- General Mortgage Indenture and Deed of Trust dated as of January 1, 1998 between OE and the Bank of New York, as Trustee. (Registration No. 333-05277, Exhibit 4(g)) 10-1 -- Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(2) 10-2 -- Amendment No. 1 dated January 4, 1974 to Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-68906, Exhibit 5(c) (3)) 10-3 -- Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(3)) 10-4 -- Amendment No. 1 dated as of January 1, 1993 to Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (1993 Form 10-K, Exhibit 10-4) 10-5 -- Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980 among the CAPCO Group. (Registration No. 2-68906, Exhibit 10-4) 10-6 -- Amendment dated as of December 23, 1993 to Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980 among the CAPCO Group. (1993 Form 10-K, Exhibit 10-6) 10-7 -- CAPCO Basic Operating Agreement, as amended September 1, 1980. (Registration No. 2-68906, Exhibit 10-5) 10-8 -- Amendment No. 1 dated August 1, 1981, and Amendment No. 2 dated September 1, 1982 to CAPCO Basic Operating Agreement, as amended September 1, 1980. (September 30, 1981 Form 10-Q, Exhibit 20-1 and 1982 Form 10-K, Exhibit 19-3, respectively) 10-9 -- Amendment No. 3 dated July 1, 1984 to CAPCO Basic Operating Agreement, as amended September 1, 1980. (1985 Form 10-K, Exhibit 10-7) 10-10 -- Basic Operating Agreement between the CAPCO Companies as amended October 1, 1991. (1991 Form 10-K, Exhibit 10-8) 10-11 -- Basic Operating Agreement between the CAPCO Companies as amended January 1, 1993. (1993 Form 10-K, Exhibit 10-11) 10-12 -- Memorandum of Agreement effective as of September 1, 1980 among the CAPCO Group. (1982 Form 10-K, Exhibit 19-2) 10-13 -- Operating Agreement for Beaver Valley Power Station Units Nos. 1 and 2 as Amended and Restated September 15, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 10-15) 10-14 -- Construction Agreement with respect to Perry Plant between the CAPCO Group dated as of July 22, 1974. (Registration No. 2-52251 of Toledo Edison Company, Exhibit 5(yy)) 10-15 -- Amendment No. 3 dated as of October 31, 1980 to the Bond Guaranty dated as of October 1, 1973, as amended, with respect to the CAPCO Group. (Registration No. 2-68906 of Pennsylvania Power Company, Exhibit 10-16) 10-16 -- Amendment No. 4 dated as of July 1, 1985 to the Bond Guaranty dated as October 1, 1973, as amended, by the CAPCO Companies to National City Bank as Bond Trustee. (1985 Form 10-K, Exhibit 10-30) 10-17 -- Amendment No. 5 dated as of May 1, 1986, to the Bond Guaranty by the CAPCO Companies to National City Bank as Bond Trustee. (1986 Form 10-K, Exhibit 10-33) 10-18 -- Amendment No. 6A dated as of December 1, 1991, to the Bond Guaranty dated as of October 1, 1973, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-33) 10-19 -- Amendment No. 6B dated as of December 30, 1991, to the Bond Guaranty dated as of October 1, 1973 by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-34) 10-20 -- Bond Guaranty dated as of December 1, 1991, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (1991 Form 10-K, Exhibit 10-35) 10-21 -- Memorandum of Understanding dated March 31, 1985 among the CAPCO Companies. (1985 Form 10-K, Exhibit 10-35) (C) 10-22 -- Ohio Edison System Executive Supplemental Life Insurance Plan. (1995 Form 10-K, Exhibit 10-44) (C) 10-23 -- Ohio Edison System Executive Incentive Compensation Plan. (1995 Form 10-K, Exhibit 10-45.) (C) 10-24 -- Ohio Edison System Restated and Amended Executive Deferred Compensation Plan. (1995 Form 10-K, Exhibit 10-46.) (C) 10-25 -- Ohio Edison System Restated and Amended Supplemental Executive Retirement Plan. (1995 Form 10-K, Exhibit 10-47.) (C) 10-26 -- Severance pay agreement between Ohio Edison Company and W. R. Holland. (1995 Form 10-K, Exhibit 10-48.) (C) 10-27 -- Severance pay agreement between Ohio Edison Company and H. P. Burg. (1995 Form 10-K, Exhibit 10-49.) (C) 10-28 -- Severance pay agreement between Ohio Edison Company and A. J. Alexander. (1995 Form 10-K, Exhibit 10-50.) (C) 10-29 -- Severance pay agreement between Ohio Edison Company and J. A. Gill. (1995 Form 10K, Exhibit 10-51.) (D) 10-30 -- Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-1.) (D) 10-31 -- Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company (now The Bank of New York), as Indenture Trustee, and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-46.) (D) 10-32 -- Amendment No. 3 dated as of May 16, 1988 to Participation Agreement dated as of March 16, 1987, as amended among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-47.) (D) 10-33 -- Amendment No. 4 dated as of November 1, 1991 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-47.) (D) 10-34 -- Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987, as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company as Lessee. (1992 Form 10-K, Exhibit 10-49.) (D) 10-35 -- Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-50.) (D) 10-36 -- Amendment No. 7 dated as of October 12, 1994 to Participation Agreement dated as of March 16, 1987 as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-54.) (D) 10-37 -- Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1986 Form 10-K, Exhibit 28-2.) (D) 10-38 -- Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1997 between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-49.) (D) 10-39 -- Amendment No. 2 dated as of November 1, 1991, to Facility Lease dated as of March 16, 1987, between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-50.) (D) 10-40 -- Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as March 16, 1987 as amended, between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited partnership, as Owner Participant and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-54.) (D) 10-41 -- Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended, between, The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-59.) (D) 10-42 -- Amendment No. 5 dated as of October 12, 1994 to Facility Lease dated as of March 16, 1987 as amended, between, The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-60.) (D) 10-43 -- Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, Lessee, and The First National Bank of Boston, Owner Trustee under a Trust dated March 16, 1987 with Chase Manhattan Realty Leasing Corporation, required by Section 3(d) of the Facility Lease. (1986 Form 10-K, Exhibit 28-3.) (D) 10-44 -- Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with the Owner Participant, Tenant. (1986 Form 10-K, Exhibit 28-4.) (D) 10-45 -- Trust Agreement dated as of March 16, 1987 between Perry One Alpha Limited Partnership, as Owner Participant, and The First National Bank of Boston. (1986 Form 10-K, Exhibit 28-5.) (D) 10-46 -- Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of March 16, 1987 with Perry One Alpha Limited Partnership, and Irving Trust Company, as Indenture Trustee. (1986 Form 10-K, Exhibit 28-6.) (D) 10-47 -- Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (1991 Form 10-K, Exhibit 10-55.) (D) 10-48 -- Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (1991 Form 10-K, Exhibit 10-56.) (D) 10-49 -- Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-7.) (D) 10-50 -- Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (1991 Form 10-K, Exhibit 10-58.) (D) 10-51 -- Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-69.) (D) 10-52 -- Amendment No. 3 dated as of October 12, 1994 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-70.) (D) 10-53 -- Partial Mortgage Release dated as of March 19, 1987 under the Indenture between Ohio Edison Company and Bankers Trust Company, as Trustee, dated as of the 1st day of August 1930. (1986 Form 10-K, Exhibit 28-8.) (D) 10-54 -- Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1986 Form 10-K, Exhibit 28-9.) (D) 10-55 -- Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, and Ohio Edison Company. (1986 Form 10-K, Exhibit 28-10.) (D) 10-56 -- Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership. (1986 Form 10-K, Exhibit 28-11.) (D) 10-57 -- Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Grantee. (1986 Form 10-K, File Exhibit 28-12.) 10-58 -- Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1986 Form 10-K, as Exhibit 28-13.) 10-59 -- Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, The Original Loan Participants Listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-65.) 10-60 -- Amendment No. 4 dated as of November 1, 1991, to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-66.) 10-61 -- Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNNP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-71.) 10-62 -- Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-80.) 10-63 -- Amendment No. 7 dated as of October 12, 1994 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-81.) 10-64 -- Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, Lessor, and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-14.) 10-65 -- Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-68.) 10-66 -- Amendment No. 2 dated as of November 1, 1991 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (1991 Form 10-K, Exhibit 10-69.) 10-67 -- Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as of March 16, 1987, as amended, between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-75.) 10-68 -- Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-76.) 10-69 -- Amendment No. 5 dated as of October 12, 1994 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-87.) 10-70 -- Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, as Lessee, and The First National Bank of Boston, as Owner Trustee under a Trust, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, required by Section 3(d) of the Facility Lease. (1986 Form 10-K, Exhibit 28-15.) 10-71 -- Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Tenant. (1986 Form 10-K, Exhibit 28-16.) 10-72 -- Trust Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and The First National Bank of Boston. (1986 Form 10-K, Exhibit 28-17.) 10-73 -- Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Irving Trust Company, as Indenture Trustee. (1986 Form 10-K, Exhibit 28-18.) 10-74 -- Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (1991 Form 10-K, Exhibit 10-74.) 10-75 -- Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (1991 Form 10-K, Exhibit 10-75.) 10-76 -- Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1986 Form 10-K, Exhibit 28-19.) 10-77 -- Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (1991 Form 10-K, Exhibit 10-77.) 10-78 -- Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-96.) 10-79 -- Amendment No. 3 dated as of October 12, 1994 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (1994 Form 10-K, Exhibit 10-97.) 10-80 -- Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1986 Form 10-K, Exhibit 28-20.) 10-81 -- Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Ohio Edison Company. (1986 Form 10-K, Exhibit 28-21.) 10-82 -- Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Buyer. (1986 Form 10-K, Exhibit 28-22.) 10-83 -- Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Grantee. (1986 Form 10-K, Exhibit 28-23.) 10-84 -- Refinancing Agreement dated as of November 1, 1991 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York, as New Collateral Trust Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-82.) 10-85 -- Refinancing Agreement dated as of November 1, 1991 among Security Pacific Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York as New Collateral Trust Trustee and Ohio Edison Company, as Lessee. (1991 Form 10-K, Exhibit 10-83.) 10-86 -- Ohio Edison Company Master Decommissioning Trust Agreement for Perry Nuclear Power Plant Unit One, Perry Nuclear Power Plant Unit Two, Beaver Valley Power Station Unit One and Beaver Valley Power Station Unit Two dated July 1, 1993. (1993 Form 10-K, Exhibit 10-94.) 10-87 -- Nuclear Fuel Lease dated as of March 31, 1989, between OES Fuel, Incorporated, as Lessor, and Ohio Edison Company, as Lessee. (1989 Form 10-K, Exhibit 10-62.) 10-88 -- Receivables Purchase Agreement dated as November 28, 1989, as amended and restated as of April 23, 1993, between OES Capital, Incorporated, Corporate Asset Funding Company, Inc. and Citicorp North America, Inc. (1994 Form 10-K, Exhibit 10-106.) 10-89 -- Guarantee Agreement entered into by Ohio Edison Company dated as of January 17, 1991. (1990 Form 10-K, Exhibit 10-64.) 10-90 -- Transfer and Assignment Agreement among Ohio Edison Company and Chemical Bank, as trustee under the OE Power Contract Trust. (1990 Form 10-K, Exhibit 10-65.) 10-91 -- Renunciation of Payments and Assignment among Ohio Edison Company, Monongahela Power Company, West Penn Power Company, and the Potomac Edison Company dated as of January 4, 1991. (1990 Form 10-K, Exhibit 10-66.) 10-92 -- Transfer and Assignment Agreement dated May 20, 1994 among Ohio Edison Company and Chemical Bank, as trustee under the OE Power Contract Trust. (1994 Form 10-K, Exhibit 10-110.) 10-93 -- Renunciation of Payments and Assignment among Ohio Edison Company, Monongahela Power Company, West Penn Power Company, and the Potomac Edison Company dated as of May 20, 1994. (1994 Form 10-K, Exhibit 10-111.) 10-94 -- Transfer and Assignment Agreement dated October 12, 1994 among Ohio Edison Company and Chemical Bank, as trustee under the OE Power Contract Trust. (1994 Form 10-K, Exhibit 10-112.) 10-95 -- Renunciation of Payments and Assignment among Ohio Edison Company, Monongahela Power Company, West Penn Power Company, and the Potomac Edison Company dated as of October 12, 1994. (1994 Form 10-K, Exhibit 10-113.) (E) 10-96 -- Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company as Lessee. (1987 Form 10-K, Exhibit 28-1.) (E) 10-97 -- Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-2.) (E) 10-98 -- Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-99.) (E) 10-99 -- Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-100.) (E) 10-100 -- Amendment No. 5 dated as of September 30, 1994 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-118.) (E) 10-101 -- Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-3.) (E) 10-102 -- Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-4.) (E) 10-103 -- Amendment No. 2 dated as of November 5, 1992, to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-103.) (E) 10-104 -- Amendment No. 3 dated as of September 30, 1994 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-122.) (E) 10-105 -- Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, Tenant. (1987 Form 10-K, Exhibit 28-5.) (E) 10-106 -- Trust Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Limited Partnership, as Owner Participant, and The First National Bank of Boston. (1987 Form 10-K, Exhibit 28-6.) (E) 10-107 -- Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-7.) (E) 10-108 -- Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with Beaver Valley Two Pi Limited Partnership and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-8.) (E) 10-109 -- Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-9.) (E) 10-110 -- Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-128.) (E) 10-111 -- Amendment No. 2 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-129.) (E) 10-112 -- Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-10.) (E) 10-113 -- Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-131.) (E) 10-114 -- Amendment No. 2 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-132.) (E) 10-115 -- Assignment, Assumption and Further Agreement dated as of September 15, 1987, among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (1987 Form 10-K, Exhibit 28-11.) (E) 10-116 -- Additional Support Agreement dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, and Ohio Edison Company. (1987 Form 10-K, Exhibit 28-12.) (F) 10-117 -- Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-13.) (F) 10-118 -- Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-14.) (F) 10-119 -- Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-114.) (F) 10-120 -- Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-115.) (F) 10-121 -- Amendment No. 5 dated as of January 12, 1993 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-139.) (F) 10-122 -- Amendment No. 6 dated as of September 30, 1994 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-140.) (F) 10-123 -- Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-15.) (F) 10-124 -- Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-16.) (F) 10-125 -- Amendment No. 2 dated as of November 5, 1992 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-118.) (F) 10-126 -- Amendment No. 3 dated as of January 12, 1993 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1992 Form 10-K, Exhibit 10-119.) (F) 10-127 -- Amendment No. 4 dated as of September 30, 1994 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-145.) (F) 10-128 -- Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, Tenant. (1987 Form 10-K, Exhibit 28-17.) (F) 10-129 -- Trust Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and The First National Bank of Boston. (1987 Form 10-K, Exhibit 28-18.) (F) 10-130 -- Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-19.) (F) 10-131 -- Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (1987 Form 10-K, Exhibit 28-20.) (F) 10-132 -- Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, Lessee. (1987 Form 10-K, Exhibit 28-21.) (F) 10-133 -- Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-151.) (F) 10-134 -- Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-152.) (F) 10-135 -- Amendment No. 3 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (1994 Form 10-K, Exhibit 10-153.) (F) 10-136 -- Assignment, Assumption and Further Agreement dated as of September 15, 1987, among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, and Toledo Edison Company. (1987 Form 10-K, Exhibit 28-22.) (F) 10-137 -- Additional Support Agreement dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, and Ohio Edison Company. (1987 Form 10-K, Exhibit 28-23.) 10-138 -- Operating Agreement dated March 10, 1987 with respect to Perry Unit No. 1 between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-24.) 10-139 -- Operating Agreement for Bruce Mansfield Units Nos. 1, 2 and 3 dated as of June 1, 1976, and executed on September 15, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-25.) 10-140 -- Operating Agreement for W. H. Sammis Unit No. 7 dated as of September 1, 1971 by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-26.) 10-141 -- OE-APS Power Interchange Agreement dated March 18, 1987, by and among Ohio Edison Company and Pennsylvania Power Company, and Monongahela Power Company and West Penn Power Company and The Potomac Edison Company. (1987 Form 10-K, Exhibit 28-27.) 10-142 -- OE-PEPCO Power Supply Agreement dated March 18, 1987, by and among Ohio Edison Company and Pennsylvania Power Company and Potomac Electric Power Company. (1987 Form 10-K, Exhibit 28-28.) 10-143 -- Supplement No. 1 dated as of April 28, 1987, to the OE-PEPCO Power Supply Agreement dated March 18, 1987, by and among Ohio Edison Company, Pennsylvania Power Company, and Potomac Electric Power Company. (1987 Form 10-K, Exhibit 28-29.) 10-144 -- APS-PEPCO Power Resale Agreement dated March 18, 1987, by and among Monongahela Power Company, West Penn Power Company, and The Potomac Edison Company and Potomac Electric Power Company. (1987 Form 10-K, Exhibit 28-30.) (A) 12.2 -- Consolidated fixed charge ratios. (A) 13.1 -- OE 2002 Annual Report to Stockholders (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed "filed" with the SEC.) (A) 21.1 -- List of Subsidiaries of the Registrant at December 31, 2002. (A) 23.1 -- Consent of Independent Accountants. (A) Provided herein in electronic format as an exhibit. (B) Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, OE has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of OE and its subsidiaries on a consolidated basis, but hereby agrees to furnish to the SEC on request any such instruments. (C) Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K. (D) Substantially similar documents have been entered into relating to three additional Owner Participants. (E) Substantially similar documents have been entered into relating to five additional Owner Participants. (F) Substantially similar documents have been entered into relating to two additional Owner Participants. Note: Reports of OE on Forms 10-Q and 10-K are on file with the SEC under number 1-2578. Pursuant to Rule 14a - 3 (10) of the Securities Exchange Act of 1934, the Company will furnish any exhibit in this Report upon the payment of the Company's expenses in furnishing such exhibit. 3. Exhibits - Penn 3-1 -- Amended and Restated Articles of Incorporation, as amended March 15, 2002. (2001 Form 10-K, Exhibit 3-1) 3-2 -- Amended and Restated By-Laws of Penn, as amended March 15, 2002. (2001 Form 10-K, Exhibit 3-2) 4-1* -- Indenture dated as of November 1, 1945, between Penn and The First National Bank of the City of New York (now Citibank, N.A.), as Trustee, as supplemented and amended by Supplemental Indentures dated as of May 1, 1948, March 1, 1950, February 1, 1952, October 1, 1957, September 1, 1962, June 1, 1963, June 1, 1969, May 1, 1970, April 1, 1971, October 1, 1971, May 1, 1972, December 1, 1974, October 1, 1975, September 1, 1976, April 15, 1978, June 28, 1979, January 1, 1980, June 1, 1981, January 14, 1982, August 1, 1982, December 15, 1982, December 1, 1983, September 6, 1984, December 1, 1984, May 30, 1985, October 29, 1985, August 1, 1987, May 1, 1988, November 1, 1989, December 1, 1990, September 1, 1991, May 1, 1992, July 15, 1992, August 1, 1992, and May 1, 1993, July 1, 1993, August 31, 1993, September 1, 1993, September 15, 1993, October 1, 1993, November 1, 1993, and August 1, 1994. (Physically filed and designated as Exhibits 2(b)(1)-1 through 2(b)(1)-15 in Registration Statement File No. 2-60837; as Exhibits 2(b)(2), 2(b)(3), and 2(b)(4) in Registration Statement File No. 2-68906; as Exhibit 4-2 in Form 10-K for 1981 File No. 1-3491; as Exhibit 19-1 in Form 10-K for 1982 File No. 1-3491; as Exhibit 19-1 in Form 10-K for 1983 File No. 1-3491; as Exhibit 19-1 in Form 10-K for 1984 File No. 1-3491; as Exhibit 19-1 in Form 10-K for 1985 File No. 1-3491; as Exhibit 19-1 in Form 10-K for 1987 File No. 1-3491; as Exhibit 19-1 in Form 10-K for 1988 File No. 1-3491; as Exhibit 19 in Form 10-K for 1989 File No. 1-3491; as Exhibit 19 in Form 10-K for 1990 File No. 1-3491; as Exhibit 19 in Form 10-K for 1991 File No. 1-3491; as Exhibit 19-1 in Form 10-K for 1992 File No. 1-3491; as Exhibit 4-2 in Form 10-K for 1993 File No. 1-3491; and as Exhibit 4-2 in Form 10-K for 1994 File No. 1-3491.) ---------- * Pursuant to paragraph (b)(4)(iii) (A) of Item 601 of Regulation S-K, Penn has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of Penn, but hereby agrees to furnish to the Commission on request any such instruments. 4-2 -- Supplemental Indenture dated as of September 1, 1995, between Penn and Citibank, N.A., as Trustee. (1995 Form 10-K, Exhibit 4-2.) 4-3 -- Supplemental Indenture dated as of June 1, 1997, between Penn and Citibank, N.A., as Trustee. (1997 Form 10-K, Exhibit 4-3.) 4-4 -- Supplemental Indenture dated as of June 1, 1998, between Penn and Citibank, N. A., as Trustee. (1998 Form 10-K, Exhibit 4-4.) 4-5 -- Supplemental Indenture dated as of September 29, 1999, between Penn and Citibank, N.A., as Trustee. (1999 Form 10-K, Exhibit 4-5.) 4-6 -- Supplemental Indenture dated as of November 15, 1999, between Penn and Citibank, N.A., as Trustee. (1999 Form 10-K, Exhibit 4-6.) 4-7 -- Supplemental Indenture dated as of June 1, 2001. (2001 Form 10-K, Exhibit 4-7) 10-1 -- Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration Statement of Ohio Edison Company, File No. 2-43102, Exhibit 5(c)(2).) 10-2 -- Amendment No. 1 dated January 4, 1974 to Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration Statement No. 2-68906, Exhibit 5 (c)(3).) 10-3 -- Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (Registration Statement of Ohio Edison Company, File No. 2-43102, Exhibit 5 (c)(3).) 10-4 -- Amendment No. 1 dated as of January 1, 1993 to Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (1993 Form 10-K, Exhibit 10-4, Ohio Edison Company.) 10-5 -- Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980 among the CAPCO Group. (Registration Statement No. 2-68906, Exhibit 10-4.) 10-6 -- Amendment dated as of December 23, 1993 to Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980 among the CAPCO Group. (1993 Form 10-K, Exhibit 10-6, Ohio Edison Company.) 10-7 -- CAPCO Basic Operating Agreement, as amended September 1, 1980. (Registration Statement No. 2-68906, as Exhibit 10-5.) 10-8 -- Amendment No. 1 dated August 1, 1981 and Amendment No. 2 dated September 1, 1982, to CAPCO Basic Operating Agreement as amended September 1, 1980. (September 30, 1981 Form 10-Q, Exhibit 20-1 and 1982 Form 10-K, Exhibit 19-3, File No. 1-2578, of Ohio Edison Company.) 10-9 -- Amendment No. 3 dated as of July 1, 1984, to CAPCO Basic Operating Agreement as amended September 1, 1980. (1985 Form 10-K, Exhibit 10-7, File No. 1-2578, of Ohio Edison Company.) 10-10 -- Basic Operating Agreement between the CAPCO Companies as amended October 1, 1991. (1991 Form 10-K, Exhibit 10-8, File No. 1-2578, of Ohio Edison Company.) 10-11 -- Basic Operating Agreement between the CAPCO Companies as amended January 1, 1993. (1993 Form 10-K, Exhibit 10-11, Ohio Edison.) 10-12 -- Memorandum of Agreement effective as of September 1, 1980, among the CAPCO Group. (1991 Form 10-K, Exhibit 19-2, Ohio Edison Company.) 10-13 -- Operating Agreement for Beaver Valley Power Station Units Nos. 1 and 2 as Amended and Restated September 15, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 10-15, File No. 1-2578, of Ohio Edison Company.) 10-14 -- Construction Agreement with respect to Perry Plant between the CAPCO Group dated as of July 22, 1974. (Registration Statement of Toledo Edison Company, File No. 2-52251, as Exhibit 5 (yy).) 10-15 -- Memorandum of Understanding dated as of March 31, 1985, among the CAPCO Companies. (1985 Form 10-K, Exhibit 10-35, File No. 1-2578, Ohio Edison Company.) (B) 10-16 -- Ohio Edison System Executive Supplemental Life Insurance Plan. (1995 Form 10-K, Exhibit 10-44, File No. 1-2578, Ohio Edison Company.) (B) 10-17 -- Ohio Edison System Executive Incentive Compensation Plan. (1995 Form 10-K, Exhibit 10-45, File No. 1-2578, Ohio Edison Company.) (B) 10-18 -- Ohio Edison System Restated and Amended Executive Deferred Compensation Plan. (1995 Form 10-K, Exhibit 10-46, File No. 1-2578, Ohio Edison Company.) (B) 10-19 -- Ohio Edison System Restated and Amended Supplemental Executive Retirement Plan. (1995 Form 10-K, Exhibit 10-47, File No. 1-2578, Ohio Edison Company.) 10-20 -- Operating Agreement for Perry Unit No. 1 dated March 10, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-24, File No. 1-2578, Ohio Edison Company.) 10-21 -- Operating Agreement for Bruce Mansfield Units Nos. 1, 2 and 3 dated as of June 1, 1976, and executed on September 15, 1987, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-25, File No. 1-2578, Ohio Edison Company.) 10-22 -- Operating Agreement for W. H. Sammis Unit No. 7 dated as of September 1, 1971, by and between the CAPCO Companies. (1987 Form 10-K, Exhibit 28-26, File No. 1-2578, Ohio Edison Company.) 10-23 -- OE-APS Power Interchange Agreement dated March 18, 1987, by and among Ohio Edison Company and Pennsylvania Power Company, and Monongahela Power Company and West Penn Power Company and The Potomac Edison Company. (1987 Form 10-K, Exhibit 28-27, File No. 1-2578, of Ohio Edison Company.) 10-24 -- OE-PEPCO Power Supply Agreement dated March 18, 1987, by and among Ohio Edison Company and Pennsylvania Power Company and Potomac Electric Power Company. (1987 Form 10-K, Exhibit 28-28, File No. 1-2578, of Ohio Edison Company.) 10-25 -- Supplement No. 1 dated as of April 28, 1987, to the OE-PEPCO Power Supply Agreement dated March 18, 1987, by and among Ohio Edison Company, Pennsylvania Power Company and Potomac Electric Power Company. (1987 Form 10-K, Exhibit 28-29, File No. 1-2578, of Ohio Edison Company.) 10-26 -- APS-PEPCO Power Resale Agreement dated March 18, 1987, by and among Monongahela Power Company, West Penn Power Company, and The Potomac Edison Company and Potomac Electric Power Company. (1987 Form 10-K, Exhibit 28-30, File No. 1-2578, of Ohio Edison Company.) 10-27 -- Pennsylvania Power Company Master Decommissioning Trust Agreement for Beaver Valley Power Station and Perry Nuclear Power Plant dated as of April 21, 1995. (Quarter ended June 30, 1995 Form 10-Q, Exhibit 10, File No. 1-3491.) 10-28 -- Nuclear Fuel Lease dated as of March 31, 1989, between OES Fuel, Incorporated, as Lessor, and Pennsylvania Power Company, as Lessee. (1989 Form 10-K, Exhibit 10-39, File No. 1-3491.) (A) 12.5 -- Fixed Charge Ratios (A) 13.4 -- Penn 2002 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed "filed" with the Securities and Exchange Commission.) (A) 23.2 -- Consent of Independent Accountants. (A) Provided herein in electronic format as an exhibit. (B) -- Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K. Pursuant to Rule 14a-3(10) of the Securities Exchange Act of 1934, the Company will furnish any exhibit in this Report upon the payment of the Company's expenses in furnishing such exhibit. 3. Exhibits - Common Exhibits to CEI and TE Exhibit Number - ------- 2(a) -- Agreement and Plan of Merger between Ohio Edison and Centerior Energy dated as of September 13, 1996 (Exhibit (2)-1, Form S-4 File No. 333-21011, filed by FirstEnergy). 2(b) -- Merger Agreement by and among Centerior Acquisition Corp., FirstEnergy and Centerior (Exhibit (2)-3, Form S-4 File No. 333-21011, filed by FirstEnergy). 4(a) -- Rights Agreement (Exhibit 4, June 25, 1996 Form 8-K, File Nos. 1-9130, 1-2323 and 1-3583). 4(b)(1) -- Form of Note Indenture between Cleveland Electric, Toledo Edison and The Chase Manhattan Bank, as Trustee dated as of June 13, 1997 (Exhibit 4(c), Form S-4 File No. 333-35931, filed by Cleveland Electric and Toledo Edison). 4(b)(2) -- Form of First Supplemental Note Indenture between Cleveland Electric, Toledo Edison and The Chase Manhattan Bank, as Trustee dated as of June 13, 1997 (Exhibit 4(d), Form S-4 File No. 333-35931, filed by Cleveland Electric and Toledo Edison). 10b(1)(a) -- CAPCO Administration Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members regarding the organization and procedures for implementing the objectives of the CAPCO Group (Exhibit 5(p), Amendment No. 1, File No. 2-42230, filed by Cleveland Electric). 10b(1)(b) -- Amendment No. 1, dated January 4, 1974, to CAPCO Administration Agreement among the CAPCO Group members (Exhibit 5(c)(3), File No. 2-68906, filed by Ohio Edison). 10b(2) -- CAPCO Transmission Facilities Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members regarding the installation, operation and maintenance of transmission facilities to carry out the objectives of the CAPCO Group (Exhibit 5(q), Amendment No. 1, File No. 2-42230, filed by Cleveland Electric). 10b(2)(1) -- Amendment No. 1 to CAPCO Transmission Facilities Agreement, dated December 23, 1993 and effective as of January 1, 1993, among the CAPCO Group members regarding requirements for payment of invoices at specified times, for payment of interest on non-timely paid invoices, for restricting adjustment of invoices after a four-year period, and for revising the method for computing the Investment Responsibility charge for use of a member's transmission facilities (Exhibit 10b(2)(1), 1993 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583). 10b(3) -- CAPCO Basic Operating Agreement As Amended January 1, 1993 among the CAPCO Group members regarding coordinated operation of the members' systems (Exhibit 10b(3), 1993 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583). 10b(4) -- Agreement for the Termination or Construction of Certain Agreement By and Among the CAPCO Group members, dated December 23, 1993 and effective as of September 1, 1980 (Exhibit 10b(4), 1993 Form 10-K, File Nos. 1-9130, 1-2323 and 1-3583). 10b(5) -- Construction Agreement, dated July 22, 1974, among the CAPCO Group members and relating to the Perry Nuclear Plant (Exhibit 5 (yy), File No. 2-52251, filed by Toledo Edison). 10b(6) -- Contract, dated as of December 5, 1975, among the CAPCO Group members for the construction of Beaver Valley Unit No. 2 (Exhibit 5 (g), File No. 2-52996, filed by Cleveland Electric). 10b(7) -- Amendment No. 1, dated May 1, 1977, to Contract, dated as of December 5, 1975, among the CAPCO Group members for the construction of Beaver Valley Unit No. 2 (Exhibit 5(d)(4), File No. 2-60109, filed by Ohio Edison). 10d(1)(a) -- Form of Collateral Trust Indenture among CTC Beaver Valley Funding Corporation, Cleveland Electric, Toledo Edison and Irving Trust Company, as Trustee (Exhibit 4(a), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(1)(b) -- Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10d(1)(a) above, including form of Secured Lease Obligation bond (Exhibit 4(b), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(1)(c) -- Form of Collateral Trust Indenture among Beaver Valley II Funding Corporation, The Cleveland Electric Illuminating Company and The Toledo Edison Company and The Bank of New York, as Trustee (Exhibit (4)(a), File No. 33-46665, filed by Cleveland Electric and Toledo Edison). 10d(1)(d) -- Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10d(1)(c) above, including form of Secured Lease Obligation Bond (Exhibit (4)(b), File No. 33-46665, filed by Cleveland Electric and Toledo Edison). 10d(2)(a) -- Form of Collateral Trust Indenture among CTC Mansfield Funding Corporation, Cleveland Electric, Toledo Edison and IBJ Schroder Bank & Trust Company, as Trustee (Exhibit 4(a), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(2)(b) -- Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10d(2)(a) above, including forms of Secured Lease Obligation bonds (Exhibit 4(b), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(3)(a) -- Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the limited partnership Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessee (Exhibit 4(c), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(3)(b) -- Form of Amendment No. 1 to Facility Lease constituting Exhibit 10d(3)(a) above (Exhibit 4(e), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(4)(a) -- Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the corporate Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees (Exhibit 4(d), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(4)(b) -- Form of Amendment No. 1 to Facility Lease constituting Exhibit 10d(4)(a) above (Exhibit 4(f), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(5)(a) -- Form of Facility Lease dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Lessor, and Cleveland Electric and Toledo Edison, Lessees (Exhibit 4(c), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(5)(b) -- Form of Amendment No. 1 to the Facility Lease constituting Exhibit 10d(5)(a) above (Exhibit 4(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(6)(a) -- Form of Participation Agreement dated as of September 15, 1987 among the limited partnership Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, CTC Beaver Valley Fund Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(a), File No. 33-18755, filed by Cleveland Electric And Toledo Edison). 10d(6)(b) -- Form of Amendment No. 1 to Participation Agreement constituting Exhibit 10d(6)(a) above (Exhibit 28(c), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(7)(a) -- Form of Participation Agreement dated as of September 15, 1987 among the corporate Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Owner Loan Participants, CTC Beaver Valley Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(b), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(7)(b) -- Form of Amendment No. 1 to Participation Agreement constituting Exhibit 10d(7)(a) above (Exhibit 28(d), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(8)(a) -- Form of Participation Agreement dated as of September 30, 1987 among the Owner Participant named therein, the Original Loan Participants listed in Schedule II thereto, as Owner Loan Participants, CTC Mansfield Funding Corporation, Meridian Trust Company, as Owner Trustee, IBJ Schroder Bank & Trust Company, as Indenture Trustee, and Cleveland Electric and Toledo Edison, as Lessees (Exhibit 28(a), File No. 33-0128, filed by Cleveland Electric and Toledo Edison). 10d(8)(b) -- Form of Amendment No. 1 to the Participation Agreement constituting Exhibit 10d(8)(a) above (Exhibit 28(b), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(9) -- Form of Ground Lease dated as of September 15, 1987 between Toledo Edison, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(e), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(10) -- Form of Site Lease dated as of September 30, 1987 between Toledo Edison, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(c), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(11) -- Form of Site Lease dated as of September 30, 1987 between Cleveland Electric, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant (Exhibit 28(d), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(12) -- Form of Amendment No. 1 to the Site Leases constituting Exhibits 10d(10) and 10d(11) above (Exhibit 4(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(13) -- Form of Assignment, Assumption and Further Agreement dated as of September 15, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Cleveland Electric, Duquesne, Ohio Edison, Pennsylvania Power and Toledo Edison (Exhibit 28(f), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(14) -- Form of Additional Support Agreement dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, and Toledo Edison (Exhibit 28(g), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(15) -- Form of Support Agreement dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Toledo Edison, Cleveland Electric, Duquesne, Ohio Edison and Pennsylvania Power (Exhibit 28(e), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(16) -- Form of Indenture, Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Toledo Edison, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Buyer (Exhibit 28(h), File No. 33-18755, filed by Cleveland Electric and Toledo Edison). 10d(17) -- Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Toledo Edison, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer (Exhibit 28(f), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(18) -- Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between Cleveland Electric, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer (Exhibit 28(g), File No. 33-20128, filed by Cleveland Electric and Toledo Edison). 10d(19) -- Forms of Refinancing Agreement, including exhibits thereto, among the Owner Participant named therein, as Owner Participant, CTC Beaver Valley Funding Corporation, as Funding Corporation, Beaver Valley II Funding Corporation, as New Funding Corporation, The Bank of New York, as Indenture Trustee, The Bank of New York, as New Collateral Trust Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees (Exhibit (28)(e)(i), File No. 33-46665, filed by Cleveland Electric and Toledo Edison). 10d(20)(a) -- Form of Amendment No. 2 to Facility Lease among Citicorp Lescaman, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(a), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10d(20)(b) -- Form of Amendment No. 3 to Facility Lease among Citicorp Lescaman, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(b), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10d(21)(a) -- Form of Amendment No. 2 to Facility Lease among US West Financial Services, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(c), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10d(21)(b) -- Form of Amendment No. 3 to Facility Lease among US West Financial Services, Inc., Cleveland Electric and Toledo Edison (Exhibit 10(d), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10d(22) -- Form of Amendment No. 2 to Facility Lease among Midwest Power Company, Cleveland Electric and Toledo Edison (Exhibit 10(e), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10e(1) -- Centerior Energy Corporation Equity Compensation Plan (Exhibit 99, Form S-8, File No. 33-59635). 3. Exhibits - Cleveland Electric Illuminating (CEI) 3a -- Amended Articles of Incorporation of CEI, as amended, effective May 28, 1993 (Exhibit 3a, 1993 Form 10-K, File No. 1-2323). 3b -- Regulations of CEI, dated April 29, 1981, as amended effective October 1, 1988 and April 24, 1990 (Exhibit 3b, 1990 Form 10-K, File No. 1-2323). 3c -- Amended and Restated Code of Regulations, dated March 15, 2002. (B)4b(1) -- Mortgage and Deed of Trust between CEI and Guaranty Trust Company of New York (now The Chase Manhattan Bank (National Association)), as Trustee, dated July 1, 1940 (Exhibit 7(a), File No. 2-4450). Supplemental Indentures between CEI and the Trustee, supplemental to Exhibit 4b(1), dated as follows: 4b(2) -- July 1, 1940 (Exhibit 7(b), File No. 2-4450). 4b(3) -- August 18, 1944 (Exhibit 4(c), File No. 2-9887). 4b(4) -- December 1, 1947 (Exhibit 7(d), File No. 2-7306). 4b(5) -- September 1, 1950 (Exhibit 7(c), File No. 2-8587). 4b(6) -- June 1, 1951 (Exhibit 7(f), File No. 2-8994). 4b(7) -- May 1, 1954 (Exhibit 4(d), File No. 2-10830). 4b(8) -- March 1, 1958 (Exhibit 2(a)(4), File No. 2-13839). 4b(9) -- April 1, 1959 (Exhibit 2(a)(4), File No. 2-14753). 4b(10) -- December 20, 1967 (Exhibit 2(a)(4), File No. 2-30759). 4b(11) -- January 15, 1969 (Exhibit 2(a)(5), File No. 2-30759). 4b(12) -- November 1, 1969 (Exhibit 2(a)(4), File No. 2-35008). 4b(13) -- June 1, 1970 (Exhibit 2(a)(4), File No. 2-37235). 4b(14) -- November 15, 1970 (Exhibit 2(a)(4), File No. 2-38460). 4b(15) -- May 1, 1974 (Exhibit 2(a)(4), File No. 2-50537). 4b(16) -- April 15, 1975 (Exhibit 2(a)(4), File No. 2-52995). 4b(17) -- April 16, 1975 (Exhibit 2(a)(4), File No. 2-53309). 4b(18) -- May 28, 1975 (Exhibit 2(c), June 5, 1975 Form 8-A, File No. 1-2323). 4b(19) -- February 1, 1976 (Exhibit 3(d)(6), 1975 Form 10 K, File No. 1-2323). 4b(20) -- November 23, 1976 (Exhibit 2(a)(4), File No. 2-57375). 4b(21) -- July 26, 1977 (Exhibit 2(a)(4), File No. 2-59401). 4b(22) -- September 7, 1977 (Exhibit 2(a)(5), File No. 2-67221). 4b(23) -- May 1, 1978 (Exhibit 2(b), June 30, 1978 Form 10-Q, File No. 1-2323). 4b(24) -- September 1, 1979 (Exhibit 2(a), September 30, 1979 Form 10-Q, File No. 1-2323). 4b(25) -- April 1, 1980 (Exhibit 4(a)(2), September 30, 1980 Form 10-Q, File No. 1-2323). 4b(26) -- April 15, 1980 (Exhibit 4(b), September 30, 1980 Form 10-Q, File No. 1-2323). 4b(27) -- May 28, 1980 (Exhibit 2(a)(4), Amendment No. 1, File No. 2-67221). 4b(28) -- June 9, 1980 (Exhibit 4(d), September 30, 1980 Form 10-Q, File No. 1-2323). 4b(29) -- December 1, 1980 (Exhibit 4(b)(29), 1980 Form 10-K, File No. 1-2323). 4b(30) -- July 28, 1981 (Exhibit 4(a), September 30, 1981, Form 10-Q, File No. 1-2323). 4b(31) -- August 1, 1981 (Exhibit 4(b), September 30, 1981, Form 10-Q, File No. 1-2323). 4b(32) -- March 1, 1982 (Exhibit 4(b)(3), Amendment No. 1, File No. 2-76029). 4b(33) -- July 15, 1982 (Exhibit 4(a), September 30, 1982 Form 10-Q, File No. 1-2323). 4b(34) -- September 1, 1982 (Exhibit 4(a)(1), September 30, 1982 Form 10-Q, File No. 1-2323). 4b(35) -- November 1, 1982 (Exhibit (a)(2), September 30, 1982 Form 10-Q, File No. 1-2323). 4b(36) -- November 15, 1982 (Exhibit 4(b)(36), 1982 Form 10-K, File No. 1-2323). 4b(37) -- May 24, 1983 (Exhibit 4(a), June 30, 1983 Form 10-Q, File No. 1-2323). 4b(38) -- May 1, 1984 (Exhibit 4, June 30, 1984 Form 10-Q, File No. 1-2323). 4b(39) -- May 23, 1984 (Exhibit 4, May 22, 1984 Form 8-K, File No. 1-2323). 4b(40) -- June 27, 1984 (Exhibit 4, June 11, 1984 Form 8-K, File No. 1-2323). 4b(41) -- September 4, 1984 (Exhibit 4b(41), 1984 Form 10-K, File No. 1-2323). 4b(42) -- November 14, 1984 (Exhibit 4b(42), 1984 Form 10 K, File No. 1-2323). 4b(43) -- November 15, 1984 (Exhibit 4b(43), 1984 Form 10-K, File No. 1-2323). 4b(44) -- April 15, 1985 (Exhibit 4(a), May 8, 1985 Form 8-K, File No. 1-2323). 4b(45) -- May 28, 1985 (Exhibit 4(b), May 8, 1985 Form 8-K, File No. 1-2323). 4b(46) -- August 1, 1985 (Exhibit 4, September 30, 1985 Form 10-Q, File No. 1-2323). 4b(47) -- September 1, 1985 (Exhibit 4, September 30, 1985 Form 8-K, File No. 1-2323). 4b(48) -- November 1, 1985 (Exhibit 4, January 31, 1986 Form 8-K, File No. 1-2323). 4b(49) -- April 15, 1986 (Exhibit 4, March 31, 1986 Form 10-Q, File No. 1-2323). 4b(50) -- May 14, 1986 (Exhibit 4(a), June 30, 1986 Form 10-Q, File No. 1-2323). 4b(51) -- May 15, 1986 (Exhibit 4(b), June 30, 1986 Form 10-Q, File No. 1-2323). 4b(52) -- February 25, 1987 (Exhibit 4b(52), 1986 Form 10-K, File No. 1-2323). 4b(53) -- October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q, File No. 1-2323). 4b(54) -- February 24, 1988 (Exhibit 4b(54), 1987 Form 10-K, File No. 1-2323). 4b(55) -- September 15, 1988 (Exhibit 4b(55), 1988 Form 10-K, File No. 1-2323). 4b(56) -- May 15, 1989 (Exhibit 4(a)(2)(i), File No. 33-32724). 4b(57) -- June 13, 1989 (Exhibit 4(a)(2)(ii), File No. 33-32724). 4b(58) -- October 15, 1989 (Exhibit 4(a)(2)(iii), File No. 33-32724). 4b(59) -- January 1, 1990 (Exhibit 4b(59), 1989 Form 10-K, File No. 1-2323). 4b(60) -- June 1, 1990 (Exhibit 4(a). September 30, 1990 Form 10-Q, File No. 1-2323). 4b(61) -- August 1, 1990 (Exhibit 4(b), September 30, 1990 Form 10-Q, File No. 1-2323). 4b(62) -- May 1, 1991 (Exhibit 4(a), June 30, 1991 Form 10-Q, File No. 1-2323). 4b(63) -- May 1, 1992 (Exhibit 4(a)(3), File No. 33-48845). 4b(64) -- July 31, 1992 (Exhibit 4(a)(3), File No. 33-57292). 4b(65) -- January 1, 1993 (Exhibit 4b(65), 1992 Form 10-K, File No. 1-2323). 4b(66) -- February 1, 1993 (Exhibit 4b(66), 1992 Form 10-K, File No. 1-2323). 4b(67) -- May 20, 1993 (Exhibit 4(a), July 14, 1993 Form 8-K, File No. 1-2323). 4b(68) -- June 1, 1993 (Exhibit 4(b), July 14, 1993 Form 8-K, File No. 1-2323). 4b(69) -- September 15, 1994 (Exhibit 4(a), September 30, 1994 Form 10-Q, File No. 1-2323). 4b(70) -- May 1, 1995 (Exhibit 4(a), September 30, 1995 Form 10-Q, File No. 1-2323). 4b(71) -- May 2, 1995 (Exhibit 4(b), September 30, 1995 Form 10-Q, File No. 1-2323). 4b(72) -- June 1, 1995 (Exhibit 4(c), September 30, 1995 Form 10-Q, File No. 1-2323). 4b(73) -- July 15, 1995 (Exhibit 4b(73), 1995 Form 10-K, File No. 1-2323). 4b(74) -- August 1, 1995 (Exhibit 4b(74), 1995 Form 10-K, File No. 1-2323). 4b(75) -- June 15, 1997 (Exhibit 4(a), Form S-4 File No. 333-35931, filed by Cleveland Electric and Toledo Edison). 4b(76) -- October 15, 1997 (Exhibit 4(a), Form S-4 File No. 333-47651, filed by Cleveland Electric). 4b(77) -- June 1, 1998 (Exhibit 4b(77), Form S-4 File No. 333-72891). 4b(78) -- October 1, 1998 (Exhibit 4b(78), Form S-4 File No. 333-72891). 4b(79) -- October 1, 1998 (Exhibit 4b(79), Form S-4 File No. 333-72891). 4b(80) -- February 24, 1999 (Exhibit 4b(80), Form S-4 File No. 333-72891). 4b(81) -- September 29, 1999. (Exhibit 4b(81), 1999 Form 10-K, File No. 1-2323). 4b(82) -- January 15, 2000. (Exhibit 4b(82), 1999 Form 10-K, File No. 1-2323). (A)4b(83) -- May 15, 2002 (A) 4b(84) -- October 1, 2002 4d -- Form of Note Indenture between Cleveland Electric and The Chase Manhattan Bank, as Trustee dated as of October 24, 1997 (Exhibit 4(b), Form S-4 File No. 333-47651, filed by Cleveland Electric). 4d(1) -- Form of Supplemental Note Indenture between Cleveland Electric and The Chase Manhattan Bank, as Trustee dated as of October 24, 1997 (Exhibit 4(c), Form S-4 File No. 333-47651, filed by Cleveland Electric). 10-1 -- Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(2).) 10-2 -- Amendment No. 1 dated January 4, 1974 to Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-68906, Exhibit 5(c)(3).) 10-3 -- Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(3).) 10-4 -- Amendment No. 1 dated as of January 1, 1993 to Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (1993 Form 10-K, Exhibit 10-4.) 10-5 -- Agreement for the Termination or Construction of Certain Agreements effective September 1, 1980, October 15, 1997 (Exhibit 4(a), Form S-4 File No. 333-47651, filed by Cleveland Electric). (A)12.3 -- Consolidated fixed charge ratios. (A)13.2 -- CEI 2002 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed "filed" with the SEC.) (A)21.2 -- List of Subsidiaries of the Registrant at December 31, 2002. (A) Provided herein in electronic format as an exhibit. (B) -- Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, CEI has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of CEI, but hereby agrees to furnish to the Commission on request any such instruments. 3. Exhibits - Toledo Edison (TE) Exhibit Number - ------- 3a -- Amended Articles of Incorporation of TE, as amended effective October 2, 1992 (Exhibit 3a, 1992 Form 10-K, File No. 1-3583). 3b -- Amended and Restated Code of Regulations, dated March 15, 2002. (2001 Form 10-K, Exhibit 3b) (B)4b(1) -- Indenture, dated as of April 1, 1947, between TE and The Chase National Bank of the City of New York (now The Chase Manhattan Bank (National Association)) (Exhibit 2(b), File No. 2-26908). 4b(2) -- September 1, 1948 (Exhibit 2(d), File No. 2-26908). 4b(3) -- April 1, 1949 (Exhibit 2(e), File No. 2-26908). 4b(4) -- December 1, 1950 (Exhibit 2(f), File No. 2-26908). 4b(5) -- March 1, 1954 (Exhibit 2(g), File No. 2-26908). 4b(6) -- February 1, 1956 (Exhibit 2(h), File No. 2-26908). 4b(7) -- May 1, 1958 (Exhibit 5(g), File No. 2-59794). 4b(8) -- August 1, 1967 (Exhibit 2(c), File No. 2-26908). 4b(9) -- November 1, 1970 (Exhibit 2(c), File No. 2-38569). 4b(10) -- August 1, 1972 (Exhibit 2(c), File No. 2-44873). 4b(11) -- November 1, 1973 (Exhibit 2(c), File No. 2-49428). 4b(12) -- July 1, 1974 (Exhibit 2(c), File No. 2-51429). 4b(13) -- October 1, 1975 (Exhibit 2(c), File No. 2-54627). 4b(14) -- June 1, 1976 (Exhibit 2(c), File No. 2-56396). 4b(15) -- October 1, 1978 (Exhibit 2(c), File No. 2-62568). 4b(16) -- September 1, 1979 (Exhibit 2(c), File No. 2-65350). 4b(17) -- September 1, 1980 (Exhibit 4(s), File No. 2-69190). 4b(18) -- October 1, 1980 (Exhibit 4(c), File No. 2-69190). 4b(19) -- April 1, 1981 (Exhibit 4(c), File No. 2-71580). 4b(20) -- November 1, 1981 (Exhibit 4(c), File No. 2-74485). 4b(21) -- June 1, 1982 (Exhibit 4(c), File No. 2-77763). 4b(22) -- September 1, 1982 (Exhibit 4(x), File No. 2-87323). 4b(23) -- April 1, 1983 (Exhibit 4(c), March 31, 1983, Form 10-Q, File No. 1-3583). 4b(24) -- December 1, 1983 (Exhibit 4(x), 1983 Form 10-K, File No. 1-3583). 4b(25) -- April 1, 1984 (Exhibit 4(c), File No. 2-90059). 4b(26) -- October 15, 1984 (Exhibit 4(z), 1984 Form 10-K, File No. 1-3583). 4b(27) -- October 15, 1984 (Exhibit 4(aa), 1984 Form 10-K, File No. 1-3583). 4b(28) -- August 1, 1985 (Exhibit 4(dd), File No. 33-1689). 4b(29) -- August 1, 1985 (Exhibit 4(ee), File No. 33-1689). 4b(30) -- December 1, 1985 (Exhibit 4(c), File No. 33-1689). 4b(31) -- March 1, 1986 (Exhibit 4b(31), 1986 Form 10-K, File No. 1-3583). 4b(32) -- October 15, 1987 (Exhibit 4, September 30, 1987 Form 10-Q, File No. 1-3583). 4b(33) -- September 15, 1988 (Exhibit 4b(33), 1988 Form 10-K, File No. 1-3583). 4b(34) -- June 15, 1989 (Exhibit 4b(34), 1989 Form 10-K, File No. 1-3583). 4b(35) -- October 15, 1989 (Exhibit 4b(35), 1989 Form 10-K, File No. 1-3583). 4b(36) -- May 15, 1990 (Exhibit 4, June 30, 1990 Form 10-Q, File No. 1-3583). 4b(37) -- March 1, 1991 (Exhibit 4(b), June 30, 1991 Form 10-Q, File No. 1-3583). 4b(38) -- May 1, 1992 (Exhibit 4(a)(3), File No. 33-48844). 4b(39) -- August 1, 1992 (Exhibit 4b(39), 1992 Form 10-K, File No. 1-3583). 4b(40) -- October 1, 1992 (Exhibit 4b(40), 1992 Form 10-K, File No. 1-3583). 4b(41) -- January 1, 1993 (Exhibit 4b(41), 1992 Form 10-K, File No. 1-3583). 4b(42) -- September 15, 1994 (Exhibit 4(b), September 30, 1994 Form 10-Q, File No. 1-3583). 4b(43) -- May 1, 1995 (Exhibit 4(d), September 30, 1995 Form 10-Q, File No. 1-3583). 4b(44) -- June 1, 1995 (Exhibit 4(e), September 30, 1995 Form 10-Q, File No. 1-3583). 4b(45) -- July 14, 1995 (Exhibit 4(f), September 30, 1995 Form 10-Q, File No. 1-3583). 4b(46) -- July 15, 1995 (Exhibit 4(g), September 30, 1995 Form 10-Q, File No. 1-3583). 4b(47) -- August 1, 1997 (Exhibit 4b(47), 1998 Form 10-K, File No. 1-3583). 4b(48) -- June 1, 1998 (Exhibit 4b (48), 1998 Form 10-K, File No. 1-3583). 4b(49) -- January 15, 2000 (Exhibit 4b(49), 1999 Form 10-K, File No. 1-3583). 4b(50) -- May 1, 2000 (Exhibit 4b(50), 2000 Form 10-K, File No. 1-3583). 4b(51) -- September 1, 2000 (A)4b(52) -- October 1, 2002 (A)12.4 -- Consolidated fixed charge ratios. (A) 13.3 -- TE 2002 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed "filed" with the SEC.) (A) 21.3 -- List of Subsidiaries of the Registrant at December 31, 2002. (A) Provided herein in electronic format as an exhibit. (B) -- Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, TE has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of TE, but hereby agrees to furnish to the Commission on request any such instruments. 3. Exhibits - Combined Exhibits for JCP&L, Met-Ed and Penelec Exhibit Number - ------- 3-A -- Restated Certificate of Incorporation of JCP&L, as amended - Incorporated by reference to Exhibit 3-A, 1990 Annual Report on Form 10-K, SEC File No. 1-3141. 3-A-1 -- Certificate of Amendment to Restated Certificate of Incorporation of JCP&L, dated June 19, 1992 - Incorporated by reference to Exhibit A-2(a), Certificate Pursuant to Rule 24, SEC File No. 70-7949. 3-A-2 -- Certificate of Amendment to Restated Certificate of Incorporation of JCP&L, dated June 19, 1992 - Incorporated by reference to Exhibit A-2(a)(i), Certificate Pursuant to Rule 24, SEC File No. 70-7949. 3-B -- By-Laws of JCP&L, as amended May 25, 1993 - Incorporated by reference to Exhibit 3-B, 1993 Annual Report on Form 10-K, SEC File No. 1-3141. 3-C -- Restated Articles of Incorporation of Met-Ed, dated March 8, 1999 - Incorporated by reference to Exhibit 3-E, 1999 Annual Report on Form 10-K, SEC File No. 1-446. 3-D -- By-Laws of Met-Ed as amended May 16, 2000. 3-E -- Restated Articles of Incorporation of Penelec, dated March 8, 1999 - Incorporated by reference to Exhibit 3-G, 1999 Annual Report on Form 10-K, SEC File No. 1-3522. 3-F -- By-Laws of Penelec as amended May 16, 2000. 4-A -- Indenture of JCP&L, dated March 1, 1946, between JCP&L and United States Trust Company of New York, Successor Trustee, as amended and supplemented by eight supplemental indentures dated December 1, 1948 through June 1, 1960 - Incorporated by reference to JCP&L's Instruments of Indebtedness Nos. 1 to 7, inclusive, and 9 and 10 filed as part of Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, SEC File Nos. 30-126 and 1-3292. 4-A-1 -- Ninth Supplemental Indenture of JCP&L, dated November 1, 1962 - Incorporated by reference to Exhibit 2-C, Registration No. 2-20732. 4-A-2 -- Tenth Supplemental Indenture of JCP&L, dated October 1, 1963 - Incorporated by reference to Exhibit 2-C, Registration No. 2-21645. 4-A-3 -- Eleventh Supplemental Indenture of JCP&L, dated October 1, 1964 - Incorporated by reference to Exhibit 5-A-3, Registration No. 2-59785. 4-A-4 -- Twelfth Supplemental Indenture of JCP&L, dated November 1, 1965 - Incorporated by reference to Exhibit 5-A-4, Registration No. 2-59785. 4-A-5 -- Thirteenth Supplemental Indenture of JCP&L, dated August 1, 1966 - Incorporated by reference to Exhibit 4-C, Registration No. 2-25124. 4-A-6 -- Fourteenth Supplemental Indenture of JCP&L, dated September 1, 1967 - Incorporated by reference to Exhibit 5-A-6, Registration No. 2-59785. 4-A-7 -- Fifteenth Supplemental Indenture of JCP&L, dated October 1, 1968 - Incorporated by reference to Exhibit 5-A-7, Registration No. 2-59785. 4-A-8 -- Sixteenth Supplemental Indenture of JCP&L, dated October 1, 1969 - Incorporated by reference to Exhibit 5-A-8, Registration No. 2-59785. 4-A-9 -- Seventeenth Supplemental Indenture of JCP&L, dated June 1, 1970 - Incorporated by reference to Exhibit 5-A-9, Registration No. 2-59785. 4-A-10 -- Eighteenth Supplemental Indenture of JCP&L, dated December 1, 1970 - Incorporated by reference to Exhibit 5-A-10, Registration No. 2-59785. 4-A-11 -- Nineteenth Supplemental Indenture of JCP&L, dated February 1, 1971 - Incorporated by reference to Exhibit 5-A-11, Registration No. 2-59785. 4-A-12 -- Twentieth Supplemental Indenture of JCP&L, dated November 1, 1971 - Incorporated by reference to Exhibit 5-A-12, Registration No. 2-59875. 4-A-13 -- Twenty-first Supplemental Indenture of JCP&L, dated August 1, 1972 - Incorporated by reference to Exhibit 5-A-13, Registration No. 2-59785. 4-A-14 -- Twenty-second Supplemental Indenture of JCP&L, dated August 1, 1973 - Incorporated by reference to Exhibit 5-A-14, Registration No. 2-59785. 4-A-15 -- Twenty-third Supplemental Indenture of JCP&L, dated October 1, 1973 - Incorporated by reference to Exhibit 5-A-15, Registration No. 2-59785. 4-A-16 -- Twenty-fourth Supplemental Indenture of JCP&L, dated December 1, 1973 - Incorporated by reference to Exhibit 5-A-16, Registration No. 2-59785. 4-A-17 -- Twenty-fifth Supplemental Indenture of JCP&L, dated November 1, 1974 - Incorporated by reference to Exhibit 5-A-17, Registration No. 2-59785. 4-A-18 -- Twenty-sixth Supplemental Indenture of JCP&L, dated March 1, 1975 - Incorporated by reference to Exhibit 5-A-18, Registration No. 2-59785. 4-A-19 -- Twenty-seventh Supplemental Indenture of JCP&L, dated July 1, 1975 - Incorporated by reference to Exhibit 5-A-19, Registration No. 2-59785. 4-A-20 -- Twenty-eighth Supplemental Indenture of JCP&L, dated October 1, 1975 - Incorporated by reference to Exhibit 5-A-20, Registration No. 2-59785. 4-A-21 -- Twenty-ninth Supplemental Indenture of JCP&L, dated February 1, 1976 - Incorporated by reference to Exhibit 5-A-21, Registration No. 2-59785. 4-A-22 -- Supplemental Indenture No. 29A of JCP&L, dated May 31, 1976 - Incorporated by reference to Exhibit 5-A-22, Registration No. 2-59785. 4-A-23 -- Thirtieth Supplemental Indenture of JCP&L, dated June 1, 1976 - Incorporated by reference to Exhibit 5-A-23, Registration No. 2-59785. 4-A-24 -- Thirty-first Supplemental Indenture of JCP&L, dated May 1, 1977 - Incorporated by reference to Exhibit 5-A-24, Registration No. 2-59785. 4-A-25 -- Thirty-second Supplemental Indenture of JCP&L, dated January 20, 1978 - Incorporated by reference to Exhibit 5-A-25, Registration No. 2-60438. 4-A-26 -- Thirty-third Supplemental Indenture of JCP&L, dated January 1, 1979 - Incorporated by reference to Exhibit A-20(b), Certificate Pursuant to Rule 24, SEC File No. 70-6242. 4-A-27 -- Thirty-fourth Supplemental Indenture of JCP&L, dated June 1, 1979 - Incorporated by reference to Exhibit A-28, Certificate Pursuant to Rule 24, SEC File No. 70-6290. 4-A-28 -- Thirty-sixth Supplemental Indenture of JCP&L, dated October 1, 1979 - Incorporated by reference to Exhibit A-30, Certificate Pursuant to Rule 24, SEC File No. 70-6354. 4-A-29 -- Thirty-seventh Supplemental Indenture of JCP&L, dated September 1, 1984 - Incorporated by reference to Exhibit A-1(cc), Certificate Pursuant to Rule 24, SEC File No. 70-7001. 4-A-30 -- Thirty-eighth Supplemental Indenture of JCP&L, dated July 1, 1985 - Incorporated by reference to Exhibit A-1(dd), Certificate Pursuant to Rule 24, SEC File No. 70-7109. 4-A-31 -- Thirty-ninth Supplemental Indenture of JCP&L, dated April 1, 1988 - Incorporated by reference to Exhibit A-1(a), Certificate Pursuant to Rule 24, SEC File No. 70-7263. 4-A-32 -- Fortieth Supplemental Indenture of JCP&L, dated June 14, 1988 - Incorporated by reference to Exhibit A-1(ff), Certificate Pursuant to Rule 24, SEC File No. 70-7603. 4-A-33 -- Forty-first Supplemental Indenture of JCP&L, dated April 1, 1989 - Incorporated by reference to Exhibit A-1(gg), Certificate Pursuant to Rule 24, SEC File No. 70-7603. 4-A-34 -- Forty-second Supplemental Indenture of JCP&L, dated July 1, 1989 - Incorporated by reference to Exhibit A-1(hh), Certificate Pursuant to Rule 24, SEC File No. 70-7603. 4-A-35 -- Forty-third Supplemental Indenture of JCP&L, dated March 1, 1991 - Incorporated by reference to Exhibit 4-A-35, Registration No. 33-45314. 4-A-36 -- Forty-fourth Supplemental Indenture of JCP&L, dated March 1, 1992 - Incorporated by reference to Exhibit 4-A-36, Registration No. 33-49405. 4-A-37 -- Forty-fifth Supplemental Indenture of JCP&L, dated October 1, 1992 - Incorporated by reference to Exhibit 4-A-37, Registration No. 33-49405. 4-A-38 -- Forty-sixth Supplemental Indenture of JCP&L, dated April 1, 1993 - Incorporated by reference to Exhibit C-15, 1992 Annual Report of GPU on Form U5S, SEC File No. 30-126. 4-A-39 -- Forty-seventh Supplemental Indenture of JCP&L, dated April 10, 1993 - Incorporated by reference to Exhibit C-16, 1992 Annual Report of GPU on Form U5S, SEC File No. 30-126. 4-A-40 -- Forty-eighth Supplemental Indenture of JCP&L, dated April 15, 1993 - Incorporated by reference to Exhibit C-17, 1992 Annual Report of GPU on Form U5S, SEC File No. 30-126. 4-A-41 -- Forty-ninth Supplemental Indenture of JCP&L, dated October 1, 1993 - Incorporated by reference to Exhibit C-18, 1993 Annual Report of GPU on Form U5S, SEC File No. 30-126. 4-A-42 -- Fiftieth Supplemental Indenture of JCP&L, dated August 1, 1994 - Incorporated by reference to Exhibit C-19, 1994 Annual Report of GPU on Form U5S, SEC File No. 30-126. 4-A-43 -- Fifty-first Supplemental Indenture of JCP&L, dated August 15, 1996 - Incorporated by reference to Exhibit 4-A-43, 1996 Annual Report on Form 10-K, SEC File No. 1-6047. 4-A-44 -- Fifty-second Supplemental Indenture of JCP&L, dated July 1, 1999 - Incorporated by reference to Exhibit 4-B-44, Registration No. 333-88783. 4-A-45 -- Fifty-third Supplemental Indenture of JCP&L, dated November 1, 1999 - Incorporated by reference to Exhibit 4-A-45, 1999 Annual Report on Form 10-K, SEC File No. 1-3141. 4-A-46 -- Subordinated Debenture Indenture of JCP&L, dated May 1, 1995 - Incorporated by reference to Exhibit A-8(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495. 4-A-47 -- Fifty-fourth Supplemental Indenture of JCP&L, dated November 7, 2001. 4-B -- Indenture of Met-Ed, dated November 1, 1944, between Met-Ed and United States Trust Company of New York, Successor Trustee, as amended and supplemented by fourteen supplemental indentures dated February 1, 1947 through May 1, 1960 - Incorporated by reference to Met-Ed's Instruments of Indebtedness Nos. 1 to 14 inclusive, and 16, filed as part of Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, SEC File Nos. 30-126 and 1-3292. 4-B-1 -- Supplemental Indenture of Met-Ed, dated December 1, 1962 - Incorporated by reference to Exhibit 2-E(1), Registration No. 2-59678. 4-B-2 -- Supplemental Indenture of Met-Ed, dated March 20, 1964 - Incorporated by reference to Exhibit 2-E(2), Registration No. 2-59678. 4-B-3 -- Supplemental Indenture of Met-Ed, dated July 1, 1965 - Incorporated by reference to Exhibit 2-E(3), Registration No. 2-59678. 4-B-4 -- Supplemental Indenture of Met-Ed, dated June 1, 1966 - Incorporated by reference to Exhibit 2-B-4, Registration No. 2-24883. 4-B-5 -- Supplemental Indenture of Met-Ed, dated March 22, 1968 - Incorporated by reference to Exhibit 4-C-5, Registration No. 2-29644. 4-B-6 -- Supplemental Indenture of Met-Ed, dated September 1, 1968 - Incorporated by reference to Exhibit 2-E(6), Registration No. 2-59678. 4-B-7 -- Supplemental Indenture of Met-Ed, dated August 1, 1969 - Incorporated by reference to Exhibit 2-E(7), Registration No. 2-59678. 4-B-8 -- Supplemental Indenture of Met-Ed, dated November 1, 1971 - Incorporated by reference to Exhibit 2-E(8), Registration No. 2-59678. 4-B-9 -- Supplemental Indenture of Met-Ed, dated May 1, 1972 - Incorporated by reference to Exhibit 2-E(9), Registration No. 2-59678. 4-B-10 -- Supplemental Indenture of Met-Ed, dated December 1, 1973 - Incorporated by reference to Exhibit 2-E(10), Registration No. 2-59678. 4-B-11 -- Supplemental Indenture of Met-Ed, dated October 30, 1974 - Incorporated by reference to Exhibit 2-E(11), Registration No. 2-59678. 4-B-12 -- Supplemental Indenture of Met-Ed, dated October 31, 1974 - Incorporated by reference to Exhibit 2-E(12), Registration No. 2-59678. 4-B-13 -- Supplemental Indenture of Met-Ed, dated March 20, 1975 - Incorporated by reference to Exhibit 2-E(13), Registration No. 2-59678. 4-B-14 -- Supplemental Indenture of Met-Ed, dated September 25, 1975 - Incorporated by reference to Exhibit 2-E(15), Registration No. 2-59678. 4-B-15 -- Supplemental Indenture of Met-Ed, dated January 12, 1976 - Incorporated by reference to Exhibit 2-E(16), Registration No. 2-59678. 4-B-16 -- Supplemental Indenture of Met-Ed, dated March 1, 1976 - Incorporated by reference to Exhibit 2-E(17), Registration No. 2-59678. 4-B-17 -- Supplemental Indenture of Met-Ed, dated September 28, 1977 - Incorporated by reference to Exhibit 2-E(18), Registration No. 2-62212. 4-B-18 -- Supplemental Indenture of Met-Ed, dated January 1, 1978 - Incorporated by reference to Exhibit 2-E(19), Registration No. 2-62212. 4-B-19 -- Supplemental Indenture of Met-Ed, dated September 1, 1978 - Incorporated by reference to Exhibit 4-A(19), Registration No. 33-48937. 4-B-20 -- Supplemental Indenture of Met-Ed, dated June 1, 1979 - Incorporated by reference to Exhibit 4-A(20), Registration No. 33-48937. 4-B-21 -- Supplemental Indenture of Met-Ed, dated January 1, 1980 - Incorporated by reference to Exhibit 4-A(21), Registration No. 33-48937. 4-B-22 -- Supplemental Indenture of Met-Ed, dated September 1, 1981 - Incorporated by reference to Exhibit 4-A(22), Registration No. 33-48937. 4-B-23 -- Supplemental Indenture of Met-Ed, dated September 10, 1981 - Incorporated by reference to Exhibit 4-A(23), Registration No. 33-48937. 4-B-24 -- Supplemental Indenture of Met-Ed, dated December 1, 1982 - Incorporated by reference to Exhibit 4-A(24), Registration No. 33-48937. 4-B-25 -- Supplemental Indenture of Met-Ed, dated September 1, 1983 - Incorporated by reference to Exhibit 4-A(25), Registration No. 33-48937. 4-B-26 -- Supplemental Indenture of Met-Ed, dated September 1, 1984 - Incorporated by reference to Exhibit 4-A(26), Registration No. 33-48937. 4-B-27 -- Supplemental Indenture of Met-Ed, dated March 1, 1985 - Incorporated by reference to Exhibit 4-A(27), Registration No. 33-48937. 4-B-28 -- Supplemental Indenture of Met-Ed, dated September 1, 1985 - Incorporated by reference to Exhibit 4-A(28), Registration No. 33-48937. 4-B-29 -- Supplemental Indenture of Met-Ed, dated June 1, 1988 - Incorporated by reference to Exhibit 4-A(29), Registration No. 33-48937. 4-B-30 -- Supplemental Indenture of Met-Ed, dated April 1, 1990 - Incorporated by reference to Exhibit 4-A(30), Registration No. 33-48937. 4-B-31 -- Amendment dated May 22, 1990 to Supplemental Indenture of Met-Ed, dated April 1, 1990 - Incorporated by reference to Exhibit 4-A(31), Registration No. 33-48937. 4-B-32 -- Supplemental Indenture of Met-Ed, dated September 1, 1992 - Incorporated by reference to Exhibit 4-A(32)(a), Registration No. 33-48937. 4-B-33 -- Supplemental Indenture of Met-Ed, dated December 1, 1993 - Incorporated by reference to Exhibit C-58, 1993 Annual Report of GPU on Form U5S, SEC File No. 30-126. 4-B-34 -- Supplemental Indenture of Met-Ed, dated July 15, 1995 - Incorporated by reference to Exhibit 4-B-35, 1995 Annual Report on Form 10-K, SEC File No. 1-446. 4-B-35 -- Supplemental Indenture of Met-Ed, dated August 15, 1996 - Incorporated by reference to Exhibit 4-B-35, 1996 Annual Report on Form 10-K, SEC File No. 1-446. 4-B-36 -- Supplemental Indenture of Met-Ed, dated May 1, 1997 - Incorporated by reference to Exhibit 4-B-36, 1997 Annual Report on Form 10-K, SEC File No. 1-446. 4-B-37 -- Supplemental Indenture of Met-Ed, dated July 1, 1999 - Incorporated by reference to Exhibit 4-B-38, 1999 Annual Report on Form 10-K, SEC File No. 1-446. 4-B-38 -- Indenture between Met-Ed and United States Trust Company of New York, dated May 1, 1999 - Incorporated by reference to Exhibit A-11(a), Certificate Pursuant to Rule 24, SEC File No. 70-9329. 4-B-39 -- Senior Note Indenture between Met-Ed and United States Trust Company of New York, dated July 1, 1999 Incorporated by reference to Exhibit C-154 to GPU, Inc.'s Annual Report on Form U5S for the year 1999, SEC File No. 30-126. 4-B-40 -- First Supplemental Indenture between Met-Ed and United States Trust Company of New York, dated August 1, 2000 - Incorporated by reference to Exhibit 4-A, June 30, 2000 Quarterly Report on Form 10-Q, SEC File No. 1-446. 4-B-41 -- Supplemental Indenture of Met-Ed, dated May 1, 2001. 4-C -- Mortgage and Deed of Trust of Penelec, dated January 1, 1942, between Penelec and United States Trust Company of New York, Successor Trustee, and indentures supplemental thereto dated March 7, 1942 through May 1, 1960 - Incorporated by reference to Penelec's Instruments of Indebtedness Nos. 1-20, inclusive, filed as a part of Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, SEC File Nos. 30-126 and 1-3292. 4-C-1 -- Supplemental Indentures to Mortgage and Deed of Trust of Penelec, dated May 1, 1961 through December 1, 1977 - Incorporated by reference to Exhibit 2-D(1) to 2-D(19), Registration No. 2-61502. 4-C-2 -- Supplemental Indenture of Penelec, dated June 1, 1978 - Incorporated by reference to Exhibit 4-A(2), Registration No. 33-49669. 4-C-3 -- Supplemental Indenture of Penelec, dated June 1, 1979 - Incorporated by reference to Exhibit 4-A(3), Registration No. 33-49669. 4-C-4 -- Supplemental Indenture of Penelec, dated September 1, 1984 - Incorporated by reference to Exhibit 4-A(4), Registration No. 33-49669. 4-C-5 -- Supplemental Indenture of Penelec, dated December 1, 1985 - Incorporated by reference to Exhibit 4-A(5), Registration No. 33-49669. 4-C-6 -- Supplemental Indenture of Penelec, dated December 1, 1986 - Incorporated by reference to Exhibit 4-A(6), Registration No. 33-49669. 4-C-7 -- Supplemental Indenture of Penelec, dated May 1, 1989 - Incorporated by reference to Exhibit 4-A(7), Registration No. 33-49669. 4-C-8 -- Supplemental Indenture of Penelec, dated December 1, 1990-Incorporated by reference to Exhibit 4-A(8), Registration No. 33-45312. 4-C-9 -- Supplemental Indenture of Penelec, dated March 1, 1992 - Incorporated by reference to Exhibit 4-A(9), Registration No. 33-45312. 4-C-10 -- Supplemental Indenture of Penelec, dated June 1, 1993 - Incorporated by reference to Exhibit C-73, 1993 Annual Report of GPU on Form U5S, SEC File No. 30-126. 4-C-11 -- Supplemental Indenture of Penelec, dated November 1, 1995 - Incorporated by reference to Exhibit 4-C-11, 1995 Annual Report on Form 10-K, SEC File No. 1-3522. 4-C-12 -- Supplemental Indenture of Penelec, dated August 15, 1996 - Incorporated by reference to Exhibit 4-C-12, 1996 Annual Report on Form 10-K, SEC File No. 1-3522. 4-C-13 -- Senior Note Indenture between Penelec and United States Trust Company of New York, dated April 1, 1999 - Incorporated by reference to Exhibit 4-C-13, 1999 Annual Report on Form 10-K, SEC File No. 1-3522. 4-C-14 -- Indenture between Penelec and United States Trust Company of New York, dated June 1, 1999 - Incorporated by reference to Exhibit A-11(a), Certificate Pursuant to Rule 24, SEC File No. 70-9327. 4-C-15 -- First Supplemental Indenture between Penelec and United States Trust Company of New York, dated August 1, 2000 - Incorporated by reference to Exhibit 4-B, June 30, 2000 Quarterly Report on Form 10-Q, SEC File No. 1-3522. 4-C-16 -- Supplemental Indenture of Penelec, dated May 1, 2001. 4-C-17 -- Supplemental Indenture No. 1 of Penelec, dated May 1, 2001. 4-D -- Amended and Restated Limited Partnership Agreement of JCP&L Capital, L.P., dated May 11, 1995 - Incorporated by reference to Exhibit A-5(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495. 4-E -- Action Creating Series A Preferred Securities of JCP&L Capital, L.P., dated May 11, 1995 - Incorporated by reference to Exhibit A-6(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495. 4-F -- Payment and Guarantee Agreement of JCP&L, dated May 18, 1995 - Incorporated by reference to Exhibit B-1(a), Certificate Pursuant to Rule 24, SEC File No. 70-8495. 4-G -- Payment and Guarantee Agreement of Met-Ed, dated May 28, 1999 - Incorporated by reference to Exhibit B-1(a), Certificate Pursuant to Rule 24, SEC No. 70-9329. 4-H -- Amendment No. 1 to Payment and Guarantee Agreement of Met-Ed, dated November 23, 1999 - Incorporated by reference to Exhibit 4-H, 1999 Annual Report on Form 10-K, SEC File No. 1-446. 4-I -- Payment and Guarantee Agreement of Penelec, dated June 16, 1999 - Incorporated by reference to Exhibit B-1(a), Certificate Pursuant to Rule 24, SEC File No. 70-9327. 4-J -- Amendment No. 1 to Payment and Guarantee Agreement of Penelec, dated November 23, 1999 - Incorporated by reference to Exhibit 4-J, 1999 Annual Report on Form 10-K, SEC File No. 1-3522. *10-A -- Deferred Remuneration Plan for Outside Directors of Jersey Central Power & Light Company, as amended and restated effective August 8, 2000. (2000 Form 10-K, Exhibit 10-H, File No. 1-3141, Jersey Central Power & Light Company.) 10-B -- Form of Amendment, effective November 7, 2001, to Deferred Remuneration Plan for Outside Directors of Jersey Central Power and Light Company. (A) 12.6 -- Consolidated fixed charge ratios - JCP&L. (A) 12.7 -- Consolidated fixed charge ratios - Met-Ed. (A) 12.8 -- Consolidated fixed charge ratios - Penelec. (A) 13.5 -- JCP&L 2002 Annual Report to Stockholders (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed "filed" with SEC.) (A) 13.6 -- Met-Ed 2002 Annual Report to Stockholders (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed "filed" with SEC.) (A) 13.7 -- Penelec 2002 Annual Report to Stockholders (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed "filed" with SEC.) (A) 21.4 -- List of Subsidiaries of JCP&L at December 31, 2002. (A) 21.5 -- List of Subsidiaries of Met-Ed at December 31, 2002. (A) 21.6 -- List of Subsidiaries of Penelec at December 31, 2002. (A) 23.3 -- Consent of Independent Accountants - JCP&L. (A) 23.4 -- Consent of Independent Accountants - Penelec. (A) 99.3 -- Chief Executive Officer Certification (JCP&L) (A) Provided here in electronic format as an exhibit. (b) Reports on Form 8-K FirstEnergy- ----------- FirstEnergy filed ten 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. OE, Penn- -------- None. CEI --- CEI filed six 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 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. 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. TE -- TE filed six 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 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. 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. Met-Ed ------ Met-Ed filed two reports on Form 8-K since September 30, 2002. 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 12, 2003 reported Met-Ed's unaudited financial information for the year ended December 31, 2002. Penelec ------- Penelec filed one report on Form 8-K since September 30, 2002. 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. JCP&L ----- JCP&L filed three reports on Form 8-K since September 30, 2002. A report dated January 17, 2003 reported the updated schedule for JCP&L rate proceedings. A report dated March 17, 2003 reported the status of the JCP&L rate proceedings. A report dated March 18, 2003 reported NJBPU audit results of JCP&L restructuring-related deferrals. Report of Independent Accountants To the Stockholders and Board of Directors of FirstEnergy Corp.: Our audit of the consolidated financial statements referred to in our report dated February 28, 2003 appearing in the 2002 Annual Report to Stockholders of FirstEnergy Corp. (which report and consolidated financial statements are incorporated by reference in this Form 10-K) also included an audit of the financial statement schedule for the year ended December 31, 2002 listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. The financial statement schedules of FirstEnergy Corp. for the years ended December 31, 2001 and 2000 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statement schedules in their report dated March 18, 2002. Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of FirstEnergy Corp.: We have audited, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements included in FirstEnergy Corp.'s Annual Report to Stockholders incorporated by reference in this Form 10-K and have issued our report thereon dated March 18, 2002. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule of consolidated valuation and qualifying accounts listed in Item 14 is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. Report of Independent Accountants To the Stockholders and Board of Directors of Ohio Edison Company: Our audit of the consolidated financial statements referred to in our report dated February 28, 2003 appearing in the 2002 Annual Report to Stockholders of Ohio Edison Company (which report and consolidated financial statements are incorporated by reference in this Form 10-K) also included an audit of the financial statement schedule for the year ended December 31, 2002 listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. The financial statement schedules of Ohio Edison Company for the years ended December 31, 2001 and 2000 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statement schedules in their report dated March 18, 2002. Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Ohio Edison Company: We have audited, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements included in Ohio Edison Company's Annual Report to Stockholders incorporated by reference in this Form 10-K and have issued our report thereon dated March 18, 2002. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule of consolidated valuation and qualifying accounts listed in Item 14 is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. Report of Independent Accountants To the Stockholders and Board of Directors of The Cleveland Electric Illuminating Company: Our audit of the consolidated financial statements referred to in our report dated February 28, 2003 appearing in the 2002 Annual Report to Stockholders of The Cleveland Electric Illuminating Company (which report and consolidated financial statements are incorporated by reference in this Form 10-K) also included an audit of the financial statement schedule for the year ended December 31, 2002 listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. The financial statement schedules of The Cleveland Electric Illuminating Company for the years ended December 31, 2001 and 2000 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statement schedules in their report dated March 18, 2002. Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of The Cleveland Electric Illuminating Company: We have audited, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements included in The Cleveland Electric Illuminating Company's Annual Report to Stockholders incorporated by reference in this Form 10-K and have issued our report thereon dated March 18, 2002. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule of consolidated valuation and qualifying accounts listed in Item 14 is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. Report of Independent Accountants To the Stockholders and Board of Directors of The Toledo Edison Company: Our audit of the consolidated financial statements referred to in our report dated February 28, 2003 appearing in the 2002 Annual Report to Shareholders of The Toledo Edison Company (which report and consolidated financial statements are incorporated by reference in this Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. The financial statement schedules of The Toledo Edison Company for the years ended December 31, 2001 and 2000 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statement schedules in their report dated March 18, 2002. Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of The Toledo Edison Company: We have audited, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements included in The Toledo Edison Company's Annual Report to Stockholders incorporated by reference in this Form 10-K and have issued our report thereon dated March 18, 2002. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule of consolidated valuation and qualifying accounts listed in Item 14 is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. Report of Independent Accountants To the Stockholders and Board of Directors of Pennsylvania Power Company: Our audit of the financial statements referred to in our report dated February 28, 2003 appearing in the 2002 Annual Report to Stockholders of Pennsylvania Power Company (which report and financial statements are incorporated by reference in this Form 10-K) also included an audit of the financial statement schedule for the year ended December 31, 2002 listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. The financial statement schedules of Pennsylvania Power Company for the years ended December 31, 2001 and 2000 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statement schedules in their report dated March 18, 2002. Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Pennsylvania Power Company: We have audited, in accordance with auditing standards generally accepted in the United States, the financial statements included in Pennsylvania Power Company's Annual Report to Stockholders incorporated by reference in this Form 10-K and have issued our report thereon dated March 18, 2002. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule of valuation and qualifying accounts listed in Item 14 is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. Report of Independent Accountants To the Stockholders and Board of Directors of Jersey Central Power & Light Company: Our audits of the consolidated financial statements referred to in our report dated February 28, 2003 appearing in the 2002 Annual Report to Stockholders of Jersey Central Power & Light Company (which report and consolidated financial statements are incorporated by reference in this Form 10-K) also included audits of the financial statement schedules for the years ended December 31, 2002 and 2000 listed in Item 15(a)(2) of this Form 10-K. In our opinion, the financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. The financial statement schedule of Jersey Central Power & Light Company for the year ended December 31, 2001 was audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on the financial statement schedule in their report dated March 18, 2002. Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Jersey Central Power & Light Company: We have audited, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements as of December 31, 2001 and for the periods from January 1, 2001 to November 6, 2001 and from November 7, 2001 to December 31, 2001, included in Jersey Central Power & Light Company's Annual Report to Stockholders incorporated by reference in this Form 10-K and have issued our report thereon dated March 18, 2002. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule of consolidated valuation and qualifying accounts listed in Item 14 is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. The information included in this schedule for the year ended December 31, 2001 has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. The consolidated financial statements as of December 31, 2000 and for each of the two years in the period ended December 31, 2000, together with the related information included in this schedule, were audited by other auditors whose report dated January 31, 2001, expressed an unqualified opinion. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. Report of Independent Accountants To the Stockholders and Board of Directors of Metropolitan Edison Company: Our audits of the consolidated financial statements referred to in our report dated February 28, 2003 appearing in the 2002 Annual Report to Stockholders of Metropolitan Edison Company (which report and consolidated financial statements are incorporated by reference in this Form 10-K) also included audits of the financial statement schedules for the years ended December 31, 2002 and 2000 listed in Item 15(a)(2) of this Form 10-K. In our opinion, the financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. The financial statement schedule of Metropolitan Edison Company for the year ended December 31, 2001 was audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on the financial statement schedule in their report dated March 18, 2002. Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Metropolitan Edison Company: We have audited, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements as of December 31, 2001 and for the periods from January 1, 2001 to November 6, 2001 and from November 7, 2001 to December 31, 2001, included in Metropolitan Edison Company's Annual Report to Stockholders incorporated by reference in this Form 10-K and have issued our report thereon dated March 18, 2002. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule of consolidated valuation and qualifying accounts listed in Item 14 is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. The information included in this schedule for the year ended December 31, 2001 has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. The consolidated financial statements as of December 31, 2000 and for each of the two years in the period ended December 31, 2000, together with the related information included in this schedule, were audited by other auditors whose report dated January 31, 2001, expressed an unqualified opinion. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. Report of Independent Accountants To the Stockholders and Board of Directors of Pennsylvania Electric Company: Our audits of the consolidated financial statements referred to in our report dated February 28, 2003 appearing in the 2002 Annual Report to Stockholders of Pennsylvania Electric Company (which report and consolidated financial statements are incorporated by reference in this Form 10-K) also included audits of the financial statement schedules for the years ended December 31, 2002 and 2000 listed in Item 15(a)(2) of this Form 10-K. In our opinion, the financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. The financial statement schedule of Pennsylvania Electric Company for the year ended December 31, 2001 was audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on the financial statement schedule in their report dated March 18, 2002. Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of Pennsylvania Electric Company: We have audited, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements as of December 31, 2001 and for the periods from January 1, 2001 to November 6, 2001 and from November 7, 2001 to December 31, 2001, included in Pennsylvania Electric Company's Annual Report to Stockholders incorporated by reference in this Form 10-K and have issued our report thereon dated March 18, 2002. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule of consolidated valuation and qualifying accounts listed in Item 14 is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. The information included in this schedule for the year ended December 31, 2001 has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. The consolidated financial statements as of December 31, 2000 and for each of the two years in the period ended December 31, 2000, together with the related information included in this schedule, were audited by other auditors whose report dated January 31, 2001, expressed an unqualified opinion. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002.
SCHEDULE II FIRSTENERGY CORP. CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 Additions ----------------------- Charged Beginning Charged to Other Ending Description Balance to Income Accounts Deductions Balance ----------- ------- --------- -------- ---------- ------- (In Thousands) Year Ended December 31, 2002: Accumulated provision for uncollectible accounts - customers......... $65,358 $43,601 $ 5,637 (a) $62,082(c) $52,514 ======= ======= ======== ======= ======= - other............. $ 7,947 $ 4,316 $ 4,089 $ 3,501 $12,851 ======= ======= ======== ======= ======= Year Ended December 31, 2001: Accumulated provision for uncollectible accounts - customers......... $32,251 $27,805 $ 41,071 (a)(b) $35,769(c) $65,358 ======= ======= ======== ======= ======= - other............. $ 4,035 $ 3,912 $ -- $ -- $ 7,947 ======= ======= ======== ======= ======= Year Ended December 31, 2000: Accumulated provision for uncollectible accounts - customers......... $ 8,219 $25,589 $ 13,245 (a) $14,802(c) $32,251 ======= ======= ======== ======= ======= - other............. $ 3,859 $11,203 $(11,027)(a) $ -- $ 4,035 ======= ======= ======== ======= ======= - ---------------- (a) Represents recoveries and reinstatements of accounts previously written off. (b) Represents amount assumed from the former GPU companies as of November 7, 2001, the effective date of the merger. (c) Represents the write-off of accounts considered to be uncollectible.
SCHEDULE II OHIO EDISON COMPANY CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 Additions ---------------------- Charged Beginning Charged to Other Ending Description Balance to Income Accounts Deductions Balance ----------- --------- --------- -------- ---------- ------- (In Thousands) Year Ended December 31, 2002: Accumulated provision for uncollectible accounts - customers...... $ 4,522 $12,792 $ 2,777 (a) $14,851(b) $ 5,240 ======= ======= ======== ======= ======= - other.......... $ 1,000 $ -- $ -- $ -- $ 1,000 ======= ======= ======== ======= ======= Year Ended December 31, 2001: Accumulated provision for uncollectible accounts.- customers...... $11,777 $16,460 $ 2,401 (a) $26,116(b) $ 4,522 ======= ======= ======== ======= ======= - other.......... $ 1,000 $ -- $ -- $ -- $ 1,000 ======= ======= ======== ======= ======= Year Ended December 31, 2000: Accumulated provision for uncollectible accounts - customers...... $ 6,452 $16,808 $ 2,218 (a) $13,701(b) $11,777 ======= ======= ======== ======= ======= - other.......... $ 1,000 $ -- $ -- $ -- $ 1,000 ======= ======= ======== ======= ======= - ---------------- (a) Represents recoveries and reinstatements of accounts previously written off. (b) Represents the write-off of accounts considered to be uncollectible.
SCHEDULE II THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 Additions ---------------------- Charged Beginning Charged to Other Ending Description Balance to Income Accounts Deductions Balance ----------- --------- --------- -------- ---------- ------- (In Thousands) Year Ended December 31, 2002: Accumulated provision for uncollectible accounts.................. $1,015 $ -- $ -- $ -- $1,015 ====== ====== ====== ====== ====== Year Ended December 31, 2001: Accumulated provision for uncollectible accounts.................. $1,000 $ 15 $ -- $ -- $1,015 ====== ====== ====== ====== ====== Year Ended December 31, 2000: Accumulated provision for uncollectible accounts.................. $1,000 $ -- $ -- $ -- $1,000 ====== ====== ====== ====== ======
SCHEDULE II THE TOLEDO EDISON COMPANY CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 Additions ---------------------- Charged Beginning Charged to Other Ending Description Balance to Income Accounts Deductions Balance ----------- --------- --------- --------- ---------- ------- (In Thousands) Year Ended December 31, 2002: Accumulated provision for uncollectible accounts..................... $ 2 $ -- $ -- $ -- $ 2 ========= ========= ========= ========= ========= Year Ended December 31, 2001: Accumulated provision for uncollectible accounts..................... $ -- $ 2 $ -- $ -- $ 2 ========= ========= ========= ========= ========= Year Ended December 31, 2000: Accumulated provision for uncollectible accounts..................... $ -- $ -- $ -- $ -- $ -- ========= ========= ========= ========= =========
SCHEDULE II PENNSYLVANIA POWER COMPANY VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 Additions ----------------------- Charged Beginning Charged to Other Ending Description Balance to Income Accounts Deductions Balance ----------- ------- --------- -------- ---------- ------- (In Thousands) Year Ended December 31, 2002: Accumulated provision for uncollectible accounts..................... $ 619 $1,808 $333 (a) $2,058(b) $ 702 ====== ====== ==== ====== ====== Year Ended December 31, 2001: Accumulated provision for uncollectible accounts..................... $ 628 $1,172 $311 (a) $1,492(b) $ 619 ====== ====== ==== ====== ====== Year Ended December 31, 2000: Accumulated provision for uncollectible accounts..................... $3,537 $ (496) $478 (a) $2,891(b) $ 628 ====== ======= ==== ====== ====== - ---------------- (a) Represents recoveries and reinstatements of accounts previously written off. (b) Represents the write-off of accounts considered to be uncollectible.
SCHEDULE II JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 Additions ----------------------- Charged Beginning Charged to Other Ending Description Balance to Income Accounts Deductions Balance ----------- ---------- --------- -------- ---------- ------- (In Thousands) Year Ended December 31, 2002: Accumulated provision for uncollectible accounts.................. $12,923 $ 9,057 $1,305(a) $18,776(b) $ 4,509 ======= ======= ====== ======= ======= Year Ended December 31, 2001: Accumulated provision for uncollectible accounts Nov. 7-Dec. 31, 2001 $12,858 $ 1,869 $ 57(a) $ 1,861(b) $12,923 ======= ======= ====== ======= ======= _________________________________________________________________________________________________________________ Jan. 1-Nov. 6, 2001 $21,479 $ 390 $1,778(a) $10,789(b) $12,858 ======= ======= ====== ======= ======= Year Ended December 31, 2000: Accumulated provision for uncollectible accounts.................. $ 6,056 $25,732 $2,427(a) $12,736(b) $21,479 ======= ======= ======= ======= ======= - ---------------- (a) Represents recoveries and reinstatements of accounts previously written off. (b) Represents the write-off of accounts considered to be uncollectible.
SCHEDULE II METROPOLITAN EDISON COMPANY CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 Additions ---------------------- Charged Beginning Charged to Other Ending Description Balance to Income Accounts Deductions Balance ----------- --------- --------- -------- ---------- ------- (In Thousands) Year Ended December 31, 2002: Accumulated provision for uncollectible accounts.................. $12,271 $ 3,332 $ 851 (a) $11,644 (b) $ 4,810 ======= ======= ====== ======= ======= Year Ended December 31, 2001: Accumulated provision for uncollectible accounts Nov. 7-Dec. 31, 2001 $11,244 $ 2,669 $ 78 (a) $ 1,720(b) $12,271 ======= ======= ====== ======= ======= ___________________________________________________________________________________________________________________ Jan. 1-Nov. 6, 2001 $13,004 $ 7,354 $ 743 (a) $ 9,857(b) $11,244 ======= ======= ====== ======== ======= Year Ended December 31, 2000: Accumulated provision for uncollectible accounts.................. $ 4,757 $18,511 $1,602 (a) $11,866(b) $13,004 ======= ======= ====== ======= ======= - ---------------- (a) Represents recoveries and reinstatements of accounts previously written off. (b) Represents the write-off of accounts considered to be uncollectible.
SCHEDULE II PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 Additions ---------------------- Charged Beginning Charged to Other Ending Description Balance to Income Accounts Deductions Balance ----------- ------- --------- -------- ---------- ------- (In Thousands) Year Ended December 31, 2002: Accumulated provision for uncollectible accounts.................. $14,719 $ 2,991 $ 704 (a) $12,198 (b) $ 6,216 ======= ======= ====== ======= ======= Year Ended December 31, 2001: Accumulated provision for uncollectible accounts Nov. 7-Dec. 31, 2001 $13,509 $ 3,686 $ 83 (a) $ 2,559 (b) $14,719 ======= ======= ====== ======= ======= ____________________________________________________________________________________________________________________ Jan. 1-Nov. 6, 2001 $14,851 $10,833 $1,069 (a) $13,244 (b) $13,509 ======= ======= ====== ======= ======= Year Ended December 31, 2000: Accumulated provision for uncollectible accounts.................. $ 5,288 $20,667 $1,539 (a) $12,643 (b) $14,851 ======= ======= ====== ======= ======= - ---------------- (a) Represents recoveries and reinstatements of accounts previously written off. (b) Represents the write-off of accounts considered to be uncollectible.
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. BY /s/ H. Peter Burg --------------------------------------- H. Peter Burg Chairman of the Board and Chief Executive Officer Date: March 24, 2003
SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/H. Peter Burg /s/Richard H. Marsh - ----------------------------------------------------- ----------------------------------------------------- H. Peter Burg Richard H. Marsh Chairman of the Board and Chief Executive Officer Senior Vice President and Chief Financial Officer and Director (Principal Executive Officer) (Principal Financial Officer) /s/Harvey L. Wagner /s/Robert N. Pokewaldt - ----------------------------------------------------- ----------------------------------------------------- Harvey L. Wagner Robert N. Pokelwaldt Vice President, Controller and Chief Accounting Director Officer (Principal Accounting Officer) /s/Anthony J. Alexander /s/Paul J. Powers - ----------------------------------------------------- ----------------------------------------------------- Anthony J. Alexander Paul J. Powers President and Chief Operating Officer Director and Director /s/Carol A. Cartwright /s/Catherine A. Rein - ----------------------------------------------------- ----------------------------------------------------- Carol A. Cartwright Catherine A. Rein Director Director /s/William F. Conway - ----------------------------------------------------- ----------------------------------------------------- William F. Conway Robert C. Savage Director Director /s/Robert B. Heisler, Jr /s/George M. Smart - ----------------------------------------------------- ----------------------------------------------------- Robert B. Heisler, Jr. George M. Smart Director Director /s/Robert L. Loughhead /s/Carlisle A. H. Trost - ----------------------------------------------------- ----------------------------------------------------- Robert L. Loughhead Carlisle A. H. Trost Director Director /s/Russell W. Maier /s/Jesse T. Williams, Sr. - ----------------------------------------------------- ----------------------------------------------------- Russell W. Maier Jesse T. Williams, Sr. Director Director /s/John M. Pietruski /s/Patricia K. Woolf - ----------------------------------------------------- ----------------------------------------------------- John M. Pietruski Patricia K. Woolf Director Director Date: March 24, 2003
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. OHIO EDISON COMPANY BY /s/ H. Peter Burg ------------------------------------------ H. Peter Burg President Date: March 24, 2003 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/ H. Peter Burg /s/ Richard H. Marsh - ------------------------------------- --------------------------------------- H. Peter Burg Richard H. Marsh President and Director Senior Vice President and Director (Principal Executive Officer) (Principal Financial Officer) /s/ Harvey L. Wagner /s/ Anthony J. Alexander - ------------------------------------- --------------------------------------- Harvey L. Wagner Anthony J. Alexander Vice President and Controller Director (Principal Accounting Officer) Date: March 24, 2003 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. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY BY /s/ H. Peter Burg ------------------------------------------ H. Peter Burg President Date: March 24, 2003 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/ H. Peter Burg /s/ Richard H. Marsh - -------------------------------------- --------------------------------------- H. Peter Burg Richard H. Marsh President and Director Senior Vice President and Director (Principal Executive Officer) (Principal Financial Officer) /s/ Harvey L. Wagner /s/ Anthony J. Alexander - -------------------------------------- --------------------------------------- Harvey L. Wagner Anthony J. Alexander Vice President and Controller Director (Principal Accounting Officer) Date: March 24, 2003 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. THE TOLEDO EDISON COMPANY BY /s/ H. Peter Burg --------------------------------- H. Peter Burg President Date: March 24, 2003 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/ H. Peter Burg /s/ Richard H. Marsh - ------------------------------------ ---------------------------------------- H. Peter Burg Richard H. Marsh President and Director Senior Vice President and Director (Principal Executive Officer) (Principal Financial Officer) /s/ Harvey L. Wagner /s/ Anthony J. Alexander - ------------------------------------ ---------------------------------------- Harvey L. Wagner Anthony J. Alexander Vice President and Controller Director (Principal Accounting Officer) Date: March 24, 2003 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. JERSEY CENTRAL POWER & LIGHT COMPANY BY /s/ Earl T. Carey -------------------------------------- Earl T. Carey President Date: March 24, 2003 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/ Earl T. Carey /s/ Richard H. Marsh - ------------------------------------- ---------------------------------------- Earl T. Carey Richard H. Marsh President and Director Senior Vice President (Principal Executive Officer) (Principal Financial Officer) /s/ Harvey L. Wagner /s/ Leila L. Vespoli - ------------------------------------- ---------------------------------------- Harvey L. Wagner Leila L. Vespoli Vice President and Controller Senior Vice President and Director (Principal Accounting Officer) /s/ Charles E. Jones /s/ Stanley C. Van Ness - ------------------------------------- ---------------------------------------- Charles E. Jones Stanley C. Van Ness Director Director /s/ Gelorma E. Persson - ------------------------------------- Gelorma E. Persson Director Date: March 24, 2003 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. METROPOLITAN EDISON COMPANY BY /s/ H. Peter Burg ---------------------------------------- H. Peter Burg President Date: March 24, 2003 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/ H. Peter Burg /s/ Richard H. Marsh - ------------------------------------- ---------------------------------------- H. Peter Burg Richard H. Marsh President and Director Senior Vice President and Director (Principal Executive Officer) (Principal Financial Officer) /s/ Harvey L. Wagner /s/ Anthony J. Alexander - ------------------------------------- ---------------------------------------- Harvey L. Wagner Anthony J. Alexander Vice President and Controller Director (Principal Accounting Officer) Date: March 24, 2003 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. PENNSYLVANIA ELECTRIC COMPANY BY /s/ H. Peter Burg ----------------------------------------------- H. Peter Burg President Date: March 24, 2003 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/ H. Peter Burg /s/ Richard H. Marsh - ------------------------------------- --------------------------------------- H. Peter Burg Richard H. Marsh President and Director Senior Vice President and Director (Principal Executive Officer) (Principal Financial Officer) /s/ Harvey L. Wagner /s/ Anthony J. Alexander - ------------------------------------- --------------------------------------- Harvey L. Wagner Anthony J. Alexander Vice President and Controller Director (Principal Accounting Officer) Date: March 24, 2003 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. PENNSYLVANIA POWER COMPANY BY /s/ H. Peter Burg ---------------------------------- H. Peter Burg Chairman of the Board and Chief Executive Officer Date: March 24, 2003 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated: /s/ H. Peter Burg /s/ Richard H. Marsh - ------------------------------------- ------------------------------------- H. Peter Burg Richard H. Marsh Chairman of the Board and Senior Vice President and Director Chief Executive Officer (Principal Financial Officer) (Principal Executive Officer) /s/ Harvey L. Wagner /s/ Anthony J. Alexander - ------------------------------------- ------------------------------------- Harvey L. Wagner Anthony J. Alexander Vice President and Controller Director (Principal Accounting Officer) Date: March 24, 2003 Certification I, H. Peter Burg, certify that: 1. I have reviewed this annual report on Form 10-K of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Metropolitan Edison Company and Pennsylvania Electric Company; 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: March 24 2003 /s/H. Peter Burg --------------------------------- H. Peter Burg Chief Executive Officer Certification I, Earl T. Carey, certify that: 1. I have reviewed this annual report on Form 10-K of Jersey Central Power & Light Company; 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: March 24, 2003 /s/Earl T. Carey ---------------------------------- Earl T. Carey Chief Executive Officer Certification I, Richard H. Marsh, certify that: 1. I have reviewed this annual report on Form 10-K of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company; 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 officers 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 officers 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 officers 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: March 24, 2003 /s/Richard H. Marsh --------------------------------------- Richard H. Marsh Chief Financial Officer EX-10 3 fe_ex10-28.txt EX. 10-1 EXEC. & DIRECTOR ICP NSO FirstEnergy Corp. ----------------- Executive and Directors Incentive Compensation Plan --------------------------------------------------- Non-Qualifying Stock Option (NSO) Agreement ------------------------------------------- Option No.: 14A Number of Options Granted: <> NSOs Option Price: $34.45 per share Option Closing Date: June 11, 2002 This Option Agreement ("Agreement") is entered into as of the 1st day of April, 2002, between FirstEnergy Corp., and ("Optionee") and is not in lieu of salary or any other compensation for services. For the purposes of this plan, the term "Company" or "FE" means FirstEnergy Corp. or its subsidiaries, singularly or collectively. SECTION ONE - AWARD On February 17, 1998, the Board of Directors ("Board") of FE adopted the FE Executive and Director Incentive Compensation Plan ("Plan"), which was approved by the common stock shareholders on April 30, 1998, and become effective May 1, 1998. As of the date of this Agreement, per the terms of the Plan, FE grants to the Optionee an option ("Option") to purchase the above number of shares of FE Common Stock ("Shares") at the option price reflected above. All Grants are considered NSOs, not subject to the provisions of section 422 of the Internal Revenue Code. SECTION TWO - GENERAL TERMS This Agreement is subject to the following terms and conditions, many of which are described in greater detail in the Plan. Please consult the Plan document for further information. Vesting Provisions These Options will become vested over a four-year period, in 25 percent increments, as reflected in the table below, unless they become exercisable sooner per the Termination of Employment table: Vesting Date Amount Vested April 1, 2003 25% April 1, 2004 50% April 1, 2005 75% April 1, 2006 100% 1 Expiration These Options expire on April 1, 2012 at 2:00 PM, Akron time unless the Options expire earlier due to termination of employment (or 2:00 PM on the last business day prior to such date, if the date falls on a Saturday, Sunday, or other day when the FirstEnergy General Office is closed). Termination of Employment
Event of Optionee's Vesting When Options Expire Further Information ------------------- ------- ------------------- ------------------- Termination of Employment ------------------------- Retirement (including early Vesting continues per Options expire on As defined under 6.8 of retirement) vesting schedule April 1, 2012 the Plan Disability Vesting continues per Options expire on As defined under 6.8 of vesting schedule April 1, 2012 the Plan Death (including death after 100% vesting upon date All options expire the Shares exercisable by retirement, disability, or Other of death earlier of one year after the beneficiary (as Terminations other than for date of death or designated under Cause) expiration of the grant Article 12 of the Plan, or by will or by the laws of descent and distribution) For "Cause" Vesting stops upon date All vested and unvested Termination for Cause of termination options are immediately is defined in section forfeited back to the 2.1.6 of the Plan Company Other Separation (including Vesting stops upon date All unvested options are You may be subject to resignation) of termination immediately forfeited the "Forfeiture and back to the Company. All Recovery" provisions vested options expire the below. earlier of 90 days after you leave the Company or expiration of the grant
Change in Control In the event of a Change in Control (as defined in section 2.1.7 of the Plan), all options under this Agreement become immediately exercisable as of the date of the Change in Control, and the provisions under the section entitled "Forfeiture and Recovery" shall not apply. Forfeiture and Recovery If it is determined, in the sole discretion of the Compensation Committee (the "Committee") of the FirstEnergy Board of Directors or its delegate, that the Optionee has breached any of the covenants below, and unless such breach has been waived by the Committee or its delegate in writing, all outstanding Options shall be immediately forfeited back to FE, and any profits resulting from the exercise of Options realized in the twelve (12) months preceding the date of termination through the date of the breach shall be immediately returned to FE. During the term of his/her employment with the Company and for a period of twenty-four (24) months following termination of employment for any reason, including without limitation, termination by mutual agreement, the Optionee expressly covenants 2 and agrees that he/she will not at any time for himself/herself or on behalf of any other person, firm, association or other entity do any of the following: 1. Participate or engage, by virtue of being employed or otherwise, directly or indirectly, in the business of selling, servicing, and/or manufacturing products, supplies or services of the kind, nature or description of those sold by the Company except pursuant to his/her employment with the Company; 2. Directly participate or engage, on the behalf of other parties, in the purchase of products, supplies or services of the kind, nature or description of those sold by the Company except pursuant to his/her employment with the Company; 3. Solicit, divert, take away or attempt to take away any of the Company's Customers or the business or patronage of any such Customers of the Company; 4. Solicit, entice, lure, employ or endeavor to employ any of the Company's employees; 5. Divulge to others or use to his/her own benefit any confidential information obtained during the course of his/her employment with Company relative to sales, services, processes, methods, machines, manufacturers, compositions, ideas, improvements, patents, trademarks, or inventions belonging to or relating to the affairs of Company; or 6. Divulge to others or use to his/her own benefit any trade secrets belonging to the Company obtained during the course of his/her employment or of which he/she became aware during the course of his/her employment with the Company. The term "Customer" shall mean any person, firm, association, corporation or other entity to which the Optionee or the Company has sold the Company's products or services within the twenty-four (24) month period immediately preceding the termination of Optionee's employment with the Company or to which the Optionee or the Company is in the process of selling its products or services, or to which the Optionee or the Company has submitted a bid, or is in the process of submitting a bid to sell the Company's products or services. FE may offset any amount owed against any compensation due to the Optionee or against any amounts otherwise due and distributable to the Optionee from any benefit plan of FE in which the Optionee has participated, in accordance with the terms of such benefit plan. Should it be necessary for FE to initiate legal action to recover any amounts due, FE shall be entitled to recover from Optionee, in addition to such amounts due, all costs, including reasonable attorneys fees, incurred as a result of such legal action. Effect on the Employment Relationship Nothing in this Agreement guarantees employment with the Company, nor does it confer any special rights or privileges to the Optionee as to the terms of employment. Adjustments In the event of any merger, reorganization, consolidation, recapitalization, separation, liquidation, stock dividend, stock split, combination, distribution, or other change in corporate structure of FE affecting the Common Stock, the Committee will adjust the number and class of securities in this option in a manner determined appropriate to prevent dilution or diminution of the Option under this Agreement. 3 Administration 1. This Agreement is governed by the laws of the State of Ohio without giving effect to the principles of the conflicts of laws. 2. The terms and conditions of this Option may be modified by the Committee: (a) In any case permitted by the terms of the Plan or this Option, (b) with the written consent of the Optionee, and/or (c) without the consent of the Optionee if the amendment is either not adverse to the interests of the Optionee or is required by law. 3. The administration of this Agreement and the Plan will be performed in accordance with Article 3 of the Plan. All determinations and decisions made by the Committee, the Board, or any delegate of the Committee as to the provisions of the Plan shall be final, conclusive, and binding on all persons. 4. Except as provided otherwise herein, the terms of this Agreement are governed at all times by the official text of the Plan and in no way alter or modify the Plan. 5. If a term is capitalized but not defined in this Agreement, it has the meaning given to it in the Plan. 6. To the extent a conflict exists between the terms of this Agreement and the provisions of the Plan, the provisions of the Plan shall govern. SECTION THREE - METHODS OF EXERCISING THE OPTION Notification to Exercise To exercise an option, the Optionee must submit to the Administrator of the Plan the information below either on a form provided by FE, a broker form, or a blank sheet of paper: 1. Number of shares being purchased, 2. The grant price, 3. The form of payment, 4. A statement of intention to exercise, 5. The signature of the Optionee, (or legal representative in the case of death or disability), and 6. Any representations or disclosures required by any applicable securities law. Method of Payment Payment for the transaction and associated brokerage fees may be made through the following methods: 1. Cash Exercise -- Delivering cash equal to the cost of the exercise. 2. Stock Swap Exercise -- Surrendering certificates of FE stock previously acquired having a Fair Market Value at the time of the exercise equal to the amount of the exercise, and, if necessary, a small amount of cash, not to exceed the price of one (1) share of stock. 3. Cashless Exercise-- Using the net proceeds from the immediate sale of stock to pay for the exercise of the Option, as directed in the written notification to exercise the option. 4 A combination of any of the above based upon Plan administrative rules. Withholding Tax FE shall have the right to deduct, withhold, or require the Optionee to surrender an amount sufficient to satisfy federal (including FICA and Medicare), state, and/or local taxes required by law to be withheld for any exercise. SECTION FOUR - TRANSFER OF OPTION The Option is not transferable during the life of the Optionee. Only the Optionee shall have the right to exercise an option, unless deceased, at which time the option may be exercised by the Optionee's beneficiary (as designated under Article 12 of the Plan or by will or by the laws of descent and distribution). FirstEnergy Corp. By _____________________________ Corporate Secretary I acknowledge receipt of this NSO Agreement and I accept and agree with the terms and conditions stated above. --------------------------------- (Signature of Optionee) - --------------------- (Date) (This is <>'s <> grant under the FE Stock Option Program.) NSO Option Agreement Grant 14A - Normal (no name).doc 04/05/02 EX-10 4 fe_ex10-29.txt EX. 10-2 BOARD OF DIRECTOR NSO 12 Board of Director ----------------- Non-Qualifying Stock Option (NSO) Agreement ------------------------------------------- for Elected and Bonus Stock Options ----------------------------------- Option No.: 12 Number of Elected Options: 4,193 NSO's Number of Bonus Options: 839 NSO's Total Options Granted: 5,032 NSO's Exercise Price: $35.15 per share This Option Agreement ("Agreement") is entered into as of January 1, 2002, between FirstEnergy Corp. ("FE"), and ___________ ("Optionee") and is in lieu of the Board of Directors retainer fee. SECTION ONE - AWARD The Board of Directors ("Directors") of FE adopted the FE Executive and Director Incentive Compensation Plan ("Plan") on February 17, 1998. The Plan was subsequently approved by the common stock shareholders on April 30, 1998, and became effective May 1, 1998. According to the terms of the Plan, the Optionee shall receive, as of the above date, the number of Options ("Options") to purchase shares of FE Common Stock ("Shares"), at the above price, based upon the Optionee's elections indicated on the Election Form signed by the Optionee on November 16, 2001. All grants are considered NSO's, not subject to the provisions of section 422 of the Code. SECTION TWO - GENERAL TERMS This Agreement is subject to the following terms and conditions as outlined in the Plan: Options Accrued All Options granted are earned in 2002 in proportion to each month served not to exceed 100%. A full month's credit will be given for time served after the first of the month. All Bonus options become fully vested after the director has served four years from the date of this grant, subject to the same restrictions as the grant. Exercise of Options These Options will become exerciseable as of January 1, 2006, which is four years after the grant unless it becomes exerciseable prior to that date due to termination from the Board. Expiration These Options expire on December 31, 2011, at 2:00 PM, Akron Time, unless the Options expire earlier due to termination from the Board (or 2:00 PM on the last business day prior to such date, if the date falls on a Saturday, Sunday, or other day when the FirstEnergy General Office is closed). 1 Termination from the Board
Event of Optionee Vesting When Options Expire Further Information ----------------- ------- ------------------- ------------------- Retirement Vesting continues per vesting Options expire on December 31, As defined by the Board schedule 2011 on November 7, 1997 Disability Vesting continues per vesting Options expire on As defined under Internal schedule December 31, 2011 Revenue Code Section 22 (3) (3) Death, including death 100% vesting on date of death All options expire the earlier Shares exercisable by the after disability, of one year after date of beneficiary (per Article retirement, or resignation death or expiration of the 12 of the Plan, or by before January 1, 2006 grant will or by the laws of descent and distribution) Death after January 1, Vesting stops upon date you All unvested options are 2006 for any reason other leave Board immediately forfeited back to than disability, the Company. All vested retirement, or For Cause options expire the earlier of one year after you leave the Board or 90 days after death, if such death occurs prior to one year after termination, or the expiration of the grant Termination For Cause Vesting stops upon date you All vested and unvested Termination for Cause is leave Board options are immediately defined in section 2.1.6 forfeited back to the Company of the Plan Other Termination, Vesting stops upon date you All unvested options are including resignation leave Board immediately forfeited back to before January 1, 2006 the Company. All vested options expire the earlier of 90 days after you leave the Board or expiration of the grant Other Termination, Vesting stops upon date you All unvested options are including resignation leave Board immediately forfeited back to after January 1, 2006 the Company. All vested options expire the earlier of one year after you leave the Board or expiration of the grant
Change in Control In the event of a Change in Control (as defined in Section 2.1.7 of the Plan), all options under this Agreement become immediately exerciseable as of the date of the Change in Control. 2 Effect on the Board Relationship Nothing in this Agreement guarantees Board membership with FE, nor does it confer any special rights or privileges to the Optionee. Adjustments In the event of any merger, reorganization, consolidation, recapitalization, separation, liquidation, stock dividend, stock split, combination, distribution, or other change in corporate structure of FE affecting the Common Stock, the Compensation Committee ("Committee") of the Board of Directors of FE will adjust the number and class of securities in this option in a manner determined appropriate to prevent dilution or diminution of the Option under this Agreement. Forfeiture 1. All Options not earned in 2002 are immediately forfeited back to the Company upon termination from the Board. 2. All Bonus Options granted are forfeited back to the Company upon termination from the Board for any reason other than retirement, death, or disability prior to January 1, 2006. Administration 1. This Agreement is governed by the laws of the State of Ohio without giving effect to the principles of the conflicts of laws. 2. The terms and conditions of this Option may be modified by the Committee: a) in any case permitted by the terms of the Plan or this Option, b) with the written consent of the Optionee, or c) without the consent of the Optionee if the amendment is either not adverse to the interests of the Optionee or is required by law. 3. The administration of this Agreement and the Plan will be performed in accordance with Article 3 of the Plan. All determinations and decisions made by the Committee, the Board, or any delegate of the Committee as to the provisions of the Plan shall be final, conclusive, and binding on all persons. 4. The terms of this Agreement are governed at all times by the official text of the Plan and in no way alter or modify the Plan. 5. If a term is capitalized but not defined in this Agreement, it has the meaning given to it in the Plan. 6. To the extent a conflict exists between the terms of this Agreement and the provisions of the Plan, the provisions of the Plan shall govern. SECTION THREE - METHODS OF EXERCISING THE OPTION Notification to Exercise To exercise an option, the Optionee must submit to the Administrator of the Plan the information below either on a form provided by FE, a broker form, or on a blank sheet of paper: 1. Number of shares being purchased, 2. The grant price, 3. The form of payment, 4. A statement of intention to exercise, 3 5. The signature of the Optionee, (or legal representative in the case of death or disability), and 6. Any representations or disclosures required by any applicable securities law. Method of Payment Payment for the transaction and associated brokerage fees may be made through the following methods: 1. Cash Exercise -- Delivering cash equal to the cost of the exercise. 2. Stock Swap Exercise -- Surrendering certificates of FE stock previously acquired having a Fair Market Value at the time of the exercise equal to the amount of the exercise, along with a small amount of cash, not to exceed the price of one (1) share of stock. 3. Cashless Exercise - Using the net proceeds from the immediate sale of stock to pay for the exercise of the Option, as directed in the written notification to exercise the option. 4. A combination of any of the above based upon Plan administrative rules. Withholding Tax Though taxes are the responsibility of the Optionee, FE shall have the right to deduct, withhold, or require the Optionee to surrender an amount sufficient to satisfy federal (including FICA and Medicare), state, and/or local taxes required by law to be withheld for any exercise. SECTION FOUR - TRANSFER OF OPTION The Option is not transferable during the life of the Optionee. Only the Optionee shall have the right to exercise an option, unless deceased, at which time the option may be exercised by Optionee's beneficiary (as described in Article 12 of the Plan or by will or by the laws of descent and distribution). FirstEnergy Corp. By _____________________________ Corporate Secretary I acknowledge receipt of this NSO Agreement and I accept and agree with the terms and conditions stated above. -------------------------------- ------------------------- (Signature of Optionee) (Date) (This is XXX's YY grant under the Stock Option Program.) Director's Stock Option Agreement.doc 02/08/02 4 EX-10 5 fe_ex10-30.txt EX. 10-3 EXEC & DIRECTOR INCENT. COMP. FIRSTENERGY CORP. EXECUTIVE AND DIRECTOR INCENTIVE COMPENSATION PLAN FE Plan effective May 1,1998 Revised November 16, 1998 Revised November 16, 1999 Amendment to Plan approved by Shareholders on May 15, 2001 Amendment to Plan approved by Shareholders on May 21, 2002 FirstEnergy Corp. Executive and Director Incentive Compensation Plan Table of Contents Page ---- Article 1 Establishment, Purpose, and Duration 1.1 Establishment of the Plan 1 1.2 Purpose of the Plan 1 1.3 Duration of the Plan 1 Article 2 Definitions and Construction 2.1 Definitions 2.1.1 Award 1 2.1.2 Beneficial Owner 1 2.1.3 Black-Scholes Value 1 2.1.4 Board or Board of Directors 1 2.1.5 Cash Award 1 2.1.6 Cause 1 2.1.7 Change in Control 2 2.1.8 Code 4 2.1.9 Committee 4 2.1.10 Company 4 2.1.11 Covered Employee 4 2.1.12 Directors' Award 4 2.1.13 Exchange Act 4 2.1.14 Fair Market Value 4 2.1.15 Incentive Stock Option or ISO 4 2.1.16 Key Employee 4 2.1.17 Nonqualified Stock Option or NSO 5 2.1.18 Option 5 2.1.19 Outside Director 5 2.1.20 Participant 5 2.1.21 Performance Share 5 2.1.22 Period of Restriction 5 2.1.23 Person 5 2.1.24 Plan 5 2.1.25 Restricted Stock 5 2.1.26 Subsidiary 5 2.1.27 Standard Rate 5 2.1.28 Stock 5 2.1.29 Stock Appreciation Right or SAR 5 2.1.30 Voting Stock 5 2.2 Gender and Number 5 2.3 Severability 5 1 FirstEnergy Corp. Executive and Director Incentive Compensation Plan Table of Contents Article 3 Administration 3.1 The Committee 5 3.2 Authority of the Committee 6 3.3 Selection of Participants 6 3.4 Decisions Binding 6 3.5 Delegation of Certain Responsibilities 6 3.6 Procedures of the Committee 7 3.7 Award Agreements 7 3.8 Conditions on Awards 7 3.9 Saturdays, Sundays, and Holidays 7 Article 4 Stock Subject to the Plan 4.1 Number of Shares 7 4.2 Lapsed Awards 8 4.3 Adjustments in Authorized Shares 8 Article 5 Eligibility and Participation 5.1 Eligibility 8 5.2 Actual Participation 8 Article 6 Stock Options 6.1 Grant of Options 8 6.2 Option Agreement 9 6.3 Option Price 9 6.4 Duration of Options 9 6.5 Exercise of Options 9 6.6 Payment 9 6.7 Restrictions on Stock Transferability 10 6.8 Termination of Employment Due to Death, Disability, 10 or Retirement 6.9 Termination of Employment for Other Reasons 10 6.10 Nontransferability of Options 11 2 FirstEnergy Corp. Executive and Director Incentive Compensation Plan Table of Contents Article 7 Stock Appreciation Rights 7.1 Grant of Stock Appreciation Rights 11 7.2 Exercise of SARS in Lieu of Options 11 7.3 Exercise of SARS in Addition to Options 11 7.4 Exercise of SARS Independent of Options 12 7.5 Payment of SAR Amount 12 7.6 Form and Timing of Payment 12 7.7 Term of SAR 12 7.8 Termination of Employment 12 7.9 Nontransferability of SARs 12 Article 8 Restricted Stock 8.1 Grant of Restricted Stock 12 8.2 Restricted Stock Agreement 12 8.3 Transferability 13 8.4 Other Restrictions 13 8.5 Certificate Legend 13 8.6 Removal of Restrictions 13 8.7 Voting Rights 13 8.8 Dividends and Other Distributions 13 8.9 Termination of Employment Due to Retirement 13 8.10 Termination of Employment Due to Death or Disability 14 8.11 Termination of Employment for Other Reasons 14 Article 9 Performance Shares 9.1 Grant of Performance Shares 14 9.2 Value of Performance Shares 14 9.3 Payment of Performance Shares 15 9.4 Committee Discretion to Adjust Awards 15 9.5 Form and Timing of Payment 15 9.6 Termination of Employment Due to Death, Disability, 15 or Retirement 9.7 Termination of Employment for Other Reasons 15 9.8 Nontransferability 16 Article 10 Cash Awards 10.1 Grant of Cash Award 16 10.2 Cash Award Performance Criteria 16 10.3 Payout of Cash awards 16 10.4 Conversion of Cash Award Payout to Restricted Stock 16 3 FirstEnergy Corp. Executive and Director Incentive Compensation Plan Table of Contents Article 11 Directors' Awards 11.1 Grant of Director's Awards 17 11.2 Conversion of Retainer to Stock 17 11.3 Conversion of Retainer to Restricted Stock 17 11.4 Conversion of Retainer to Stock Options 17 Article 12 Beneficiary Designation 17 Article 13 Rights of Employees 13.1 Employment 18 13.2 Participation 18 13.3 No Implied Rights; Rights on Termination of Service 18 13.4 No Right to Company Assets 18 Article 14 Change in Control 14.1 Stock Based Awards 18 14.2 All Awards Other than Stock Based Awards 18 Article 15 Amendment, Modification, and Termination 15.1 Amendment, Modification, and Termination 19 15.2 Awards Previously Granted 19 15.3 Deferral of Payments and Distributions 19 Article 16 Withholding and Deferral 16.1 Tax Withholding 19 16.2 Stock Delivery or Withholding 19 Article 17 Successors 20 Article 18 Requirements of Law 18.1 Requirements of Law 20 18.2 Governing Law 20 4 FirstEnergy Corp. Executive and Director Incentive Compensation Plan Scope of Revision Rev. 4 Increase the number of shares under the Plan as approved by Shareholders on May 21, 2002. Rev. 3 Clairfy that 6.8 includes early retirement. Put 6.8 in plain English. Increase the number of shares under the Plan and the limits as approved by Shareholders on May 15, 2001. Add "vesting or forfeiture" to 8.4 to strengthen the substantial forfeiture clause as required by IRS. Rev. 2 Change definition of Fair Market Value from 20 day average to high and low on date of grant. Rev. 1 Reformatted from Landscape to Portrait, made numbering consistence throughout document. Included Table of Contents and Scope of Revision pages. Changed the NQSO acronym to NSO throughout. Clarified that the Chief Executive Officer could grant awards for all Key employees, except those defined as Covered Employees. Incorporated the changes to Rule 16b-3 requirements. Clarified how dates referenced in the Agreements are to be handled when the date falls on a Saturday, Sunday, or Holiday. Clarified how cashless exercises are handled. Clarified that exercising portions of grants are permissible. Added language to 18.2 regarding conflicts of law. Rev. 0 Plan approved by FirstEnergy Board of Directors on February 17, 1998 Plan approved by common shareholders on April 30, 1998 Plan became effective on May 1, 1998 5 FirstEnergy Corp. Executive and Director Incentive Compensation Plan ARTICLE 1 ESTABLISHMENT, PURPOSE, AND DURATION ------------------------------------ 1.1 ESTABLISHMENT OF THE PLAN. FirstEnergy Corp. (hereinafter referred to as "FirstEnergy"), established, effective May 1, 1998, an incentive compensation plan known as the "Executive and Director Incentive Compensation Plan" (hereinafter referred to as the "Plan"), which permits the grant of Incentive Stock Options, Non-qualified Stock Options, Stock Appreciation Rights, Restricted Stock, Performance Shares, Cash Awards and Directors' Awards. 1.2 PURPOSE OF THE PLAN. The purpose of the Plan is to promote the success of the Company and its Subsidiaries by providing incentives to Key Employees and Directors that will link their personal interests to the long-term financial success of the Company and its Subsidiaries, and to growth in shareholder value. The Plan is designed to provide flexibility to the Company and its Subsidiaries in their ability to motivate, attract, and retain the services of Key Employees upon whose judgment, interest, and special effort the successful conduct of their operations is largely dependent. The Plan is intended to preserve maximum deductibility of all awards made under the plan within the structure of Section 162(m) of the Internal Revenue Code of 1986 as amended "the Code". 1.3 DURATION OF THE PLAN. The Plan will commence on May 1, 1998, as described in Section 1.1 herein. The Plan shall remain in effect, subject to the right of the Board of Directors to terminate the Plan at any time, until all Shares subject to it shall have been purchased or acquired according to the provisions herein. ARTICLE 2 DEFINITIONS AND CONSTRUCTION ---------------------------- 2.1. DEFINITIONS. Whenever used in the Plan, the following terms shall have the meanings set forth below and, when the meaning is intended, the initial letter of the word is capitalized: 2.1.1 "Award" means, individually or collectively, a grant under this Plan of Incentive Stock Options, Nonqualified Stock Options, Stock Appreciation Rights, Restricted Stock, Performance Shares, Cash Awards or Directors' Awards. 2.1.2 "Beneficial Owner" shall have the meaning ascribed to such term in Rule 13d-3 of the General Rules and Regulations under the Exchange Act. 2.1.3 "Black-Scholes Value" means the value of one stock option as calculated by the Black-Scholes Valuation Model as prescribed under Financial Accounting Standard 123. 2.1.4 "Board" or "Board of Directors" means the Board of Directors of the Company. 2.1.5 "Cash Award" means an award in the form of cash that is a bonus made pursuant to the terms of Article 10. 2.1.6 "Cause" shall mean the occurrence of any one of the following: (i) the willful and continued failure by a Participant to substantially perform his/her duties (other than any such failure resulting from the Participant's disability), after a written demand for substantial performance is delivered to the Participant that specifically identifies the manner in which the Company or any of its Subsidiaries, as the case may be, believes that the Participant has not substantially 1 FirstEnergy Corp. Executive and Director Incentive Compensation Plan performed his/her duties, and the Participant has failed to remedy the situation within ten (10) business days of receiving such notice; or (ii) the Participant's conviction for committing a felony or a crime involving an act of moral turpitude, dishonesty or misfeasance; or (iii) the willful engaging by the Participant in gross misconduct materially and demonstrably injurious to the Company or any of its Subsidiaries. However, no act, or failure to act, on the Participant's part shall be considered "willful" unless done, or omitted to be done, by the Participant not in good faith and without reasonable belief that his/her action or omission was in the best interest of the Company or any of its Subsidiaries. 2.1.7 "Change in Control" shall mean: (i) The acquisition by Person of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 50% (25%if such Person proposes any individual for election to the Board or any member of the Board is the representative of such Person) or more of either (a) the then outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or (b) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Outstanding Company Voting Securities"); provided, however, that the following acquisitions shall not constitute a Change in Control: (1) any acquisition directly from the Company (excluding an acquisition by virtue of the exercise of a conversion privilege), (2) any acquisition by the Company, (3) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company, or (4) any acquisition by any corporation pursuant to a reorganization, merger or consolidation, if, following such reorganization, merger or consolidation, the conditions described in clauses (a), (b) and (c) of subsection (iii) of this subsection 2.1.7 are satisfied; or (ii) Individuals who, as of the date hereof, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of either an actual or threatened election contest (as such terms are used in Rule 14a-11 of the Regulation 14A promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or (iii) Approval by the shareholders of the Company of a reorganization, merger or consolidation, in each case, unless, following such reorganization, merger or consolidation, 2 FirstEnergy Corp. Executive and Director Incentive Compensation Plan (a) more than 75% of, respectively, the then outstanding shares of common stock of the corporation resulting from such reorganization, merger or consolidation and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such reorganization, merger or consolidation in substantially the same proportions as their ownership, immediately prior to such reorganization, merger or consolidation, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (b) no Person (excluding the Company, an employee benefit plan (or related trust) of the Company or such corporation resulting from such reorganization, merger or consolidation and any Person beneficially owning, immediately prior to such reorganization, merger or consolidation, directly or indirectly, 25% or more of the Outstanding Company Common Stock or Outstanding Voting Securities, as the case may be) beneficially owns, directly or indirectly, 25% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such reorganization, merger or consolidation or the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors and (c) at least a majority of the members of the board of directors of the corporation resulting from such reorganization, merger or consolidation were members of the Incumbent Board at the time of the execution of the initial agreement providing for such reorganization, merger or consolidation; or (iv) Approval by the shareholders of the Company of (a) a complete liquidation or dissolution of the Company or (b) the sale or other disposition of all or substantially all of the assets of the Company, other than to a corporation, with respect to which following such sale or other disposition (1) more than 75% of, respectively, the then outstanding shares of common stock of such corporation and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such sale or other disposition in substantially the same proportion as their ownership, immediately prior to such sale or other disposition, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case 3 FirstEnergy Corp. Executive and Director Incentive Compensation Plan may be, (2) no Person (excluding the Company and any employee benefit plan (or related trust) of the Company or such corporation and any Person beneficially owning, immediately prior to such sale or other disposition, directly or indirectly, 25% or more of the Outstanding Company Common Stock or Outstanding Company Voting Securities, as the case may be) beneficially owns, directly or indirectly, 25% or more of, respectively, the then outstanding share of common stock of such corporation and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors and (3) at least a majority of the members of the board of directors of such corporation were members of the Incumbent Board at the time of the execution of the initial agreement or action of the Board providing for such sale or other disposition of assets of the Company. However, in no event shall a Change in Control be deemed to have occurred, with respect to a Participant, if the Participant is part of a purchasing group, which consummates the Change in Control transaction. The Participant shall be deemed "part of a purchasing group. . . " for purposes of the preceding sentence if the Participant is an equity participant or has agreed to become an equity participant in the purchasing company or group (except for (i) passive ownership of less than 5% of the voting securities of the purchasing company or (ii) ownership of equity participation in the purchasing company or group which is otherwise not deemed to be significant, as determined prior to the Change in Control by a majority of the non-employee continuing members of the Board). 2.1.8 "Code" means the Internal Revenue Code of 1986, as amended from time to time. 2.1.9 "Committee" means the Compensation Committee of the Board. 2.1.10 "Company" means FirstEnergy Corp., an Ohio corporation, or any successor thereto as provided in Article 17 herein. 2.1.11 "Covered Employee" means any Participant designated prior to the grant of Stock Options, Stock Appreciation Rights, Restricted Stock, Performance Shares or Cash Award by the Committee who is or may be a "covered employee" within the meaning of Section 162(m)(3) of the Code in the year in which such Stock Options, Stock Appreciation Rights, Restricted Stock, Performance Shares or Cash Award are taxable to such Participant. 2.1.12 "Directors' Award" means an Award made pursuant to Article 11 of this Plan. 2.1.13 "Exchange Act" means the Securities Exchange Act of 1934, as amended from time to time. 2.1.14 "Fair Market Value" means the average of the high and low sale prices of the common stock as reported on the composite tape of the New York Stock Exchange for the date in which the determination of the fair market value is made, or, if there are no sales of common stock on that date, then on the next preceding date on which there were sales of common stock. 2.1.15 "Incentive Stock Option" or "ISO" means an option to purchase Stock, granted under Article 6 herein, which is designated as an incentive stock option and is intended to meet the requirements of Section 422 of the Code. 2.1.16 "Key Employee" means an employee of the Company or any of its Subsidiaries, including an employee who is an officer or a director of the Company or any of its Subsidiaries, who, in the opinion of the Committee, can contribute significantly to the growth and profitability of the Company and its Subsidiaries. "Key Employee" also may include any other employee, identified by the Committee, in special situations involving extraordinary performance, promotion, retention, or recruitment. The granting of an 4 FirstEnergy Corp. Executive and Director Incentive Compensation Plan Award under this Plan shall be deemed a determination by the Committee that such employee is a Key Employee, but shall not create a right to remain a Key Employee. 2.1.17 "Nonqualified Stock Option" or "NSO" means an option to purchase Stock, granted under Article 6 herein, which is not intended to be an Incentive Stock Option. 2.1.18 "Option" means an Incentive Stock Option or a Nonqualified Stock Option. 2.1.19 "Outside Director" means any director who qualifies as an "outside director" as that term is defined in Code Section 162(m) and the regulations issued thereunder. 2.1.20 "Participant" means a Key Employee or Director who has been granted an Award under the Plan. 2.1.21 "Performance Share" means an Award, designated as a performance share, granted to a Participant pursuant to Article 9 herein. 2.1.22 "Period of Restriction" means the period during which the transfer or sale of Shares of Restricted Stock by the participant is restricted. 2.1.23 "Person" shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a "group" as defined in Section 13(d) thereof. 2.1.24 "Plan" means this Executive and Director Incentive Compensation Plan of FirstEnergy Corp., as herein described and as hereafter from time to time amended. 2.1.25 "Restricted Stock" means an Award of Stock granted to a Participant pursuant to Article 8 herein. 2.1.26 "Subsidiary" shall mean any corporation of which more than 50% (by number of votes) of the Voting Stock at the time outstanding is owned, directly or indirectly, by the Company. 2.1.27 "Standard Rate" means the electric utility median base salary level for a given position as determined in the judgment of the Committee. 2.1.28 "Stock" or "Shares" means the common stock with a 10 cent par value of the Company. 2.1.29 "Stock Appreciation Right" or "SAR" means an Award, designated as a Stock Appreciation Right, granted to a Participant pursuant to Article 7 herein. 2.1.30 "Voting Stock" shall mean securities of any class or classes of stock of a corporation, the holders of which are ordinarily, in the absence of contingencies, entitled to elect a majority of the corporate directors. 2.2 GENDER AND NUMBER. Except where otherwise indicated by the context, any masculine term used herein also shall include the feminine, the plural shall include the singular, and the singular shall include the plural. 2.3. SEVERABILITY. In the event any provision of the Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had not been included. ARTICLE 3 ADMINISTRATION -------------- 3.1 THE COMMITTEE. The Plan shall be administered by the Committee, which consists of not less than three Directors who shall be appointed from time to time by, and shall serve at the discretion of, the Board of Directors. To the extent required to comply with Rule 16b-3 under the Exchange 5 FirstEnergy Corp. Executive and Director Incentive Compensation Plan Act, each member of the Committee shall qualify as a "Non-Employee Director" as defined in Rule 16b-3 or any successor definition adopted by the Securities and Exchange Commission. To the extent required to comply with Code Section 162(m), each member of the Committee shall also be an Outside Director. 3.2 AUTHORITY OF THE COMMITTEE. Subject to the provisions of the Plan, the Committee shall have full power to construe and interpret the Plan; to establish, amend or waive rules and regulations for its administration; to accelerate the exercisability of any Award or the end of a performance period or the termination of any Period of Restriction or any award agreement, or any other instrument relating to an Award under the Plan; and (subject to the provisions of Article 15 herein) to amend the terms and conditions of any outstanding Option, Stock Appreciation Right or other Award to the extent such terms and conditions are within the discretion of the Committee as provided in the Plan. Notwithstanding the foregoing, the Committee shall have no authority to adjust upwards the amount payable to a Covered Employee with respect to a particular Award, to take any of the foregoing actions, or to take any other action to the extent that such action or the Committee's ability to take such action would cause any Award under the Plan to any Covered Employee to fail to qualify as "performance-based compensation" within the meaning of Code Section 162(m)(4) and the regulations issued thereunder. Subject to section 4.3, in no event shall the Committee have the right to i) cancel outstanding Options or SARs for the purpose of replacing or regranting such Options or SARs with an exercise price that is less than the original exercise price of the Option or SAR, or ii) change the Option Price of an Option or SAR to an exercise price that is less than the original Option or SAR exercise price, without first obtaining the approval of shareholders. Also notwithstanding the foregoing, no action of the Committee (other than pursuant to Section 4.3 hereof or Section 9.4 hereof) may, without the consent of the person or persons entitled to exercise any outstanding Option or Stock Appreciation Right or to receive payment of any other outstanding Award, adversely affect the rights of such person or persons. 3.3 SELECTION OF PARTICIPANTS. The Committee shall have the authority to grant Awards under the Plan, from time to time, to such Key Employees and Directors as may be selected by it. The Committee shall select Participants from among those who they have identified as being Key Employees or Directors. 3.4 DECISIONS BINDING. All determinations and decisions made by the Committee pursuant to the provisions of the Plan and all related orders or resolutions of the Board of Directors shall be final, conclusive and binding on all persons, including the Company and its Subsidiaries, its stockholders, employees, and Participants and their estates and beneficiaries, and such determinations and decisions shall not be reviewable. 3.5 DELEGATION OF CERTAIN RESPONSIBILITIES. The Committee may, in its sole discretion, delegate to an officer or officers of the Company the administration of the Plan under this Article 3; provided, however, that no such delegation by the Committee shall be made with respect to the administration of the Plan as it affects Directors of the Company or Covered Employees and provided further that the Committee may not delegate its authority to correct errors, omissions or inconsistencies in the Plan. The Committee may delegate to the Chief Executive Officer of the Company its authority under this Article 3 to grant Awards to Key Employees who are not 6 FirstEnergy Corp. Executive and Director Incentive Compensation Plan Covered Employees. All authority delegated by the Committee under this Section 3.5 shall be exercised in accordance with the provisions of the Plan and any guidelines for the exercise of such authority that may from time to time be established by the Committee. 3.6 PROCEDURES OF THE COMMITTEE. All determinations of the Committee shall be made by not less than a majority of its members present at the meeting (in person or otherwise) at which a quorum is present. A majority of the entire Committee shall constitute a quorum for the transaction of business. Any action required or permitted to be taken at a meeting of the Committee may be taken without a meeting if a unanimous written consent, which sets forth the action, is signed by each member of the Committee and filed with the minutes for proceedings of the Committee. Service on the Committee shall constitute service as a director of the Company so that members of the Committee shall be entitled to indemnification, limitation of liability and reimbursement of expenses with respect to their services as members of the Committee to the same extent that they are entitled under the Company's Articles of Incorporation and Ohio law for their services as directors of the Company. 3.7 AWARD AGREEMENTS. Stock-based Awards under the Plan shall be evidenced by an award agreement, which shall be signed by an authorized officer of the Company or delegate and by the Participant, and shall contain such terms and conditions as may be approved by the Committee. Such terms and conditions need not be the same in all cases. 3.8 CONDITIONS ON AWARDS. Notwithstanding any other provision of the Plan, the Board or the Committee may impose such conditions on any Award (including, without limitation, the right of the Board or the Committee to limit the time of exercise to specified periods). Notwithstanding any other provisions of the Plan, all Awards under this Plan shall be subject to the following conditions: (i) Except in the case of death, no SAR, ISO, NSO or other option granted pursuant to Article 6 shall be exercisable for at least six months after its grant; and (ii) Except in the case of death, no Restricted Stock or Performance Share (or a Share issued in payment thereof) shall be sold for at least six months after its grant. 3.9 SATURDAYS, SUNDAYS AND HOLIDAYS. When a date referenced in an award Agreement falls on a Saturday, Sunday or other day when the FirstEnergy General Office is closed, the date reference will revert back to the day prior to such date. ARTICLE 4 STOCK SUBJECT TO THE PLAN ------------------------- 4.1 NUMBER OF SHARES. Subject to adjustment as provided in Section 4.3 herein, the aggregate number of Shares that may be delivered under the Plan at any time shall not exceed 22,500,000 Shares of common stock of the Company. No more than three-quarters of such aggregate number of such Shares shall be issued as Restricted Stock under Article 8 of the Plan or as Performance Shares under Article 9. Stock delivered under the Plan may consist, in whole or in part, of authorized and unissued shares, treasury shares or shares purchased on the open market. The 7 FirstEnergy Corp. Executive and Director Incentive Compensation Plan exercise of a Stock Appreciation Right, whether paid in cash or Stock, shall be deemed to be an issuance of Stock under the Plan. 4.2 LAPSED AWARDS. If any Award granted under this Plan terminates, expires, or lapses for any reason, any Stock subject to such Award again shall be available for the grant of an Award under the Plan, subject to Section 7.2 herein. If the value of any Performance Shares issued under Article 9 are paid in cash after a Performance Period has ended, such stock subject to such award shall again be available for the grant of an award under the Plan. 4.3 ADJUSTMENTS IN AUTHORIZED SHARES. In the event of any merger, reorganization, consolidation, recapitalization, separation, liquidation, stock dividend, split-up, share combination, or other change in the corporate structure of the Company affecting the Stock, such adjustment shall be made in the number and class of shares which may be delivered under the Plan, and in the number and class of and/or price of shares subject to outstanding Options, Stock Appreciation Rights, Restricted Stock Awards and Performance Shares, granted under the Plan, as may be determined to be appropriate and equitable by the Committee, in its sole discretion, to prevent dilution or enlargement of rights; and provided that the number of shares subject to any Award shall always be a whole number. Any adjustment of an Incentive Stock Option under this paragraph shall be made in such a manner so as not to constitute a modification within the meaning of Section 425(h)(3) of the Code. ARTICLE 5 ELIGIBILITY AND PARTICIPATION ----------------------------- 5.1 ELIGIBILITY. Persons eligible to receive Awards under all Articles of this Plan except Article 11 include all employees of the Company and its Subsidiaries who, in the opinion of the Committee, are Key Employees. Key Employees may include employees who are members of the Board, but may not include Directors who are not employees. Directors who are not employees may receive Awards under this Plan exclusively under Articles 6 and 8, subject to Article 11. 5.2 ACTUAL PARTICIPATION. Subject to the provisions of the Plan, the Committee may from time to time select those Key Employees to whom Awards shall be granted and determine the nature and amount of each Award. No employee shall have any right to be granted an Award under this Plan even if previously granted an Award. ARTICLE 6 STOCK OPTIONS ------------- 6.1 GRANT OF OPTIONS. Subject to the terms and provisions of the Plan, Options may be granted to Participants at any time and from time to time as shall be determined by the Committee. The maximum number of Shares subject to Options granted to any individual Participant in any calendar year shall be five hundred thousand (500,000) Shares. The Committee shall have the sole discretion, subject to the requirements of the Plan, to determine the actual number of Shares subject to Options granted to any Participant. The Committee may grant any type of Option to purchase Stock that is permitted by law at the time of grant, including, but not limited to, ISO's and NSO's. However, no employee may receive an Award of Incentive Stock Options that are 8 FirstEnergy Corp. Executive and Director Incentive Compensation Plan first exercisable during any calendar year to the extent that the aggregate Fair Market Value of the Stock (determined at the time the options are granted) exceeds $100,000. Nothing in this Article 6 shall be deemed to prevent the grant of NSO's in excess of the maximum established by Section 422 of the Code. Unless otherwise expressly provided at the time of grant, Options granted under the Plan will be NSO's. Notwithstanding any other provision of the Plan, no ISO shall be granted after May 1, 2008. 6.2 OPTION AGREEMENT. Each Option grant shall be evidenced by an Option agreement that shall specify the type of Option granted, the Option price, the duration of the Option, the number of Shares to which the Option pertains, and such other provisions as the Committee shall determine. The Option agreement shall specify whether the Option is intended to be an Incentive Stock Option within the meaning of Section 422 of the Code, or a Nonqualified Stock Option whose grant is not intended to be subject to the provisions of Code Section 422. 6.3 OPTION PRICE. The purchase price per share of Stock covered by an Option shall be determined by the Committee but shall not be less than 100% of the Fair Market Value of such Stock on the date the Option is granted. An Incentive Stock Option granted to an Employee who, at the time of grant, owns (within the meaning of Section 425(d) of the Code) Stock possessing more than 10% of the total combined voting power of all classes of stock of the Company, shall have an exercise price which is at least 110% of the Fair Market Value of the Stock subject to the Option. 6.4 DURATION OF OPTIONS. Each Option shall expire at such time as the Committee shall determine at the time of grant; provided, however, that no Option shall be exercisable later than the tenth (10th) anniversary date of its grant. 6.5 EXERCISE OF OPTIONS. Subject to Section 3.8 herein, Options granted under the Plan shall be exercisable at such times and be subject to such restrictions and conditions as the Committee shall in each instance approve, which need not be the same for all Participants. All options within a single grant need not be exercised at one time. 6.6 PAYMENT. Options shall be exercised by the delivery of a written notice to the Company setting forth the number of Shares with respect to which the Option is to be exercised, accompanied by full payment for the Shares. The Option price upon exercise of any Option shall be payable to the Company in full either: (a) in cash or its equivalent; (b) by tendering Shares of previously acquired Stock having a Fair Market Value at the time of exercise equal to the total Option price, (c) by foregoing compensation under rules established by the Committee, (d) by delivery by the Participant of irrevocable instructions to an approved broker to promptly deliver to the Company the amount of the sale or loan proceeds to pay the exercise price, or (e) such other consideration as the Committee may deem appropriate. 9 FirstEnergy Corp. Executive and Director Incentive Compensation Plan The proceeds from such a payment shall be added to the general funds of the Company and shall be used for general corporate purposes. As soon as practicable, after the Company's receipt of written notification and payment, the Participant shall receive either: (i) stock certificates in an appropriate amount based upon the number of Options exercised, issued in the Participant's name: (ii) cash in an amount equal to the difference between the sale price of such Shares and the Option price less taxes and administrative expenses; or (iii) a combination of the foregoing. 6.7 RESTRICTIONS ON STOCK TRANSFERABILITY. The Committee shall impose such restrictions on any Shares acquired pursuant to the exercise of an Option under the Plan as it may deem advisable, including, without limitation, restrictions under applicable Federal securities law, under the requirements of any stock exchange upon which such Shares are then listed and under any blue sky or state securities laws applicable to such Shares. 6.8 TERMINATION OF EMPLOYMENT DUE TO DEATH, DISABILITY, OR RETIREMENT. In the event the employment of a Participant is terminated by reason of death, any of such Participant's outstanding Options shall become immediately exercisable at any time prior to the expiration date of the Options or within one year after such date of termination of employment, whichever period is shorter, by such person or persons as shall have acquired the Participant's rights under the Option pursuant to Article 12 hereof or by will or by the laws of descent and distribution. In the event the employment of a Participant is terminated by reason of disability or retirement, including early retirement, (as defined under the then established rules of the Company or any of its Subsidiaries, as the case may be), any of such Participant's outstanding Options shall continue to vest per the vesting schedule of the Participant's Option Agreement; provided, however, that if the Participant subsequently dies with unexercised options, the vesting and exercisaeability will be governed by the first sentence of 6.8. Notwithstanding the foregoing to the contrary, the Committee may, in its sole discretion, lengthen the exercise period up to the expiration date for an individual participant if it deems this is in the best interest of the Company. In the case of Incentive Stock Options, the favorable tax treatment prescribed under Section 422 of the Internal Revenue Code of l986, as amended, may not be available if the Options are not exercised within the Code Section 422 prescribed time period after termination of employment for death, disability, or retirement. 6.9 TERMINATION OF EMPLOYMENT FOR OTHER REASONS. If the employment of a Participant shall terminate for any reason other than death, disability, retirement (including early retirement) or for Cause, the Participant shall have the right to exercise such Participant's outstanding Options within 90 days after the date of his termination, but in no event beyond the expiration of the term of the Options and only to the extent that the Participant was entitled to exercise the Options at the date of his termination of employment. In its sole discretion, the Committee may extend the 90 days to up to one year but, however, in no event beyond the expiration date of the Option. 10 FirstEnergy Corp. Executive and Director Incentive Compensation Plan If the employment of the Participant shall terminate for Cause, all of the Participant's outstanding Options shall be immediately forfeited back to the Company. 6.10 NONTRANSFERABILITY OF OPTIONS. No Option granted under the Plan may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, otherwise than by will or by the laws of descent and distribution. Further, all Options granted to a Participant under the Plan shall be exercisable during his lifetime only by such Participant. ARTICLE 7 STOCK APPRECIATION RIGHTS ------------------------- 7.1 GRANT OF STOCK APPRECIATION RIGHTS. Subject to the terms and conditions of the Plan, Stock Appreciation Rights may be granted to Participants, at the discretion of the Committee, in any of the following forms: (a) in lieu of Options; (b) in addition to Options; (c) independent of Options; or (d) in any combination of (a), (b), or (c). The maximum numbers of Shares subject to SARs granted to any individual Participant in any calendar year shall be five hundred thousand (500,000) Shares. Subject to the immediately preceding sentence, the Committee shall have the sole discretion, subject to the requirements of the Plan, to determine the actual number of Shares subject to SARs granted to any Participant. 7.2 EXERCISE OF SARS IN LIEU OF OPTIONS. SARs granted in lieu of Options may be exercised for all or part of the Shares subject to the related Option upon the surrender of the related Options representing the right to purchase an equivalent number of Shares. The SAR may be exercised only with respect to the Shares of Stock for which its related Option is then exercisable. Option Stock with respect to which the SAR shall have been exercised may not be subject again to an Award under the Plan. Notwithstanding any other provision of the Plan to the contrary, with respect to a SAR granted in lieu of an Incentive Stock Option: (i) the SAR will expire no later than the expiration of the underlying Incentive Stock Option; (ii) the SAR amount may be for no more than one hundred percent (100%) of the difference between the exercise price of the underlying Incentive Stock Option and the Fair Market Value of the Stock subject to the underlying Incentive Stock Option at the time the SAR is exercised; and (iii) the SAR may be exercised only when the Fair Market Value of the Stock subject to the Incentive Stock Option exceeds the exercise price of the Incentive Stock Option. 7.3 EXERCISE OF SARS IN ADDITION TO OPTIONS. SARs granted in addition to Options shall be deemed to be exercised upon the exercise of the related Options. The deemed exercise of SARs granted in addition to Options shall not necessitate a reduction in the number of related Options. 11 FirstEnergy Corp. Executive and Director Incentive Compensation Plan 7.4 EXERCISE OF SARS INDEPENDENT OF OPTIONS. Subject to Section 3.8 herein and Section 7.5 herein, SARs granted independently of Options may be exercised upon whatever terms and conditions the Committee, in its sole discretion, imposes upon the SARs, including, but not limited to, a corresponding proportional reduction in previously granted Options. 7.5 PAYMENT OF SAR AMOUNT. Upon exercise of the SAR, the holder shall be entitled to receive payment of an amount determined by multiplying: (a) The difference between the market price of a Share on the date of exercise over the price fixed by the Committee at the date of grant (which price shall not be less than 100% of the market price of a Share on the date of grant) (the Exercise Price); by (b) The number of Shares with respect to which the SAR is exercised. 7.6 FORM AND TIMING OF PAYMENT. Payment to a Participant, upon SAR exercise, will be made in cash or stock, at the discretion of the Committee, as soon as administratively possible after exercise. 7.7 TERM OF SAR. The term of an SAR granted under the Plan shall not exceed ten years. 7.8 TERMINATION OF EMPLOYMENT. In the event the employment of a Participant is terminated by reason of death, disability, retirement (including early retirement), or any other reason, the exercisability of any outstanding SAR granted in lieu of or in addition to an Option shall terminate in the same manner as its related Option as specified under Sections 6.8 and 6.9 herein. The exercisability of any outstanding SARs granted independent of Options also shall terminate in the manner provided under Sections 6.8 and 6.9 hereof. 7.9 NONTRANSFERABILITY OF SARS. No SAR granted under the Plan may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. Further, all SARs granted to a Participant under the Plan shall be exercisable during his lifetime only by such Participant. ARTICLE 8 RESTRICTED STOCK ---------------- 8.1 GRANT OF RESTRICTED STOCK. Subject to the terms and provisions of the Plan, the Committee, at any time and from time to time, may grant Shares of Restricted Stock under the Plan to such Participants and in such amounts, as it shall determine. The Committee may condition the vesting or lapse of the Period of Restriction established pursuant to Section 8.3 upon the attainment of one or more of the performance goals utilized for purposes of Performance Shares pursuant to Article 9 hereof. As required for valuation of grants under the Plan, Restricted Stock will be valued at its Fair Market Value. The maximum number of Shares subject to issuance as Restricted Stock granted to any individual Participant in any calendar year is two hundred fifty thousand (250,000) Shares. 8.2 RESTRICTED STOCK AGREEMENT. Each Restricted Stock grant shall be evidenced by a Restricted Stock agreement that shall specify the Period of Restriction, or periods, the number of Shares of Restricted Stock granted, and such other provisions as the Committee shall determine. 12 FirstEnergy Corp. Executive and Director Incentive Compensation Plan 8.3 TRANSFERABILITY. Except as provided in this Article 8 or in Section 3.8 herein, the Shares of Restricted Stock granted hereunder may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated until the termination of the applicable Period of Restriction or for such period of time as shall be established by the Committee and as shall be specified in the Restricted Stock agreement, or upon earlier satisfaction of other conditions (including any performance goals) as specified by the Committee in its sole discretion and set forth in the Restricted Stock agreement. All rights with respect to the Restricted Stock granted to a Participant under the Plan shall be exercisable during his lifetime only by such Participant. 8.4 OTHER RESTRICTIONS. The Committee shall impose such other restrictions on any Shares of Restricted Stock granted pursuant to the Plan as it may deem advisable including, without limitation, vesting or forfeiture restrictions under applicable Federal or state securities laws, and the Committee may legend certificates representing Restricted Stock to give appropriate notice of such restrictions. 8.5 CERTIFICATE LEGEND. In addition to any legends placed on certificates pursuant to Section 8.4 herein, each certificate representing Shares of Restricted Stock granted pursuant to the Plan shall bear the following legend: "The sale or other transfer of the shares of stock represented by this certificate, whether voluntary, involuntary, or by operation of law, is subject to certain restrictions on transfer set forth in the Executive and Director Incentive Compensation Plan of FirstEnergy Corp., in the rules and administrative procedures adopted pursuant to such Plan, and in a Restricted Stock Agreement dated __________. A copy of the Plan, such rules and procedures, and such Restricted Stock agreement may be obtained from the Secretary of FirstEnergy Corp." 8.6 REMOVAL OF RESTRICTIONS. Except as otherwise provided in this Article, Shares of Restricted Stock covered by each Restricted Stock grant made under the Plan shall become freely transferable by the Participant after the last day of the Period of Restriction. Once the Shares are released from the restrictions, the Participant shall be entitled to have the legend required by Section 8.5 removed from his Stock certificate. 8.7 VOTING RIGHTS. During the Period of Restriction, Participants holding Shares of Restricted Stock granted hereunder may exercise full voting rights with respect to those Shares. 8.8 DIVIDENDS AND OTHER DISTRIBUTIONS. During the Period of Restriction, Participants holding Shares of Restricted Stock granted hereunder shall be entitled to receive all dividends and other distributions paid with respect to those Shares while they are so held. If any such dividends or distributions are paid in Shares, the Shares shall be subject to the same restrictions on transferability as the Shares of Restricted Stock with respect to which they were paid. 8.9 TERMINATION OF EMPLOYMENT DUE TO RETIREMENT (including early retirement). In the event that a Participant terminates his employment with the Company or any of its Subsidiaries because of retirement (as defined under the then established rules of the Company or 13 FirstEnergy Corp. Executive and Director Incentive Compensation Plan any of its Subsidiaries, as the case may be), the Committee in its sole discretion (subject to Section 3.8 herein) may waive or modify the restrictions remaining on any or all Shares of Restricted Stock as it deems appropriate. 8.10 TERMINATION OF EMPLOYMENT DUE TO DEATH OR DISABILITY. In the event a Participant's employment is terminated because of death or disability (as defined under the then established rules of the Company or any of its Subsidiaries, as the case may be) during the Period of Restriction, any remaining Period of Restriction applicable to the Restricted Stock shall automatically terminate and, except as otherwise provided in Section 8.4. herein, the Shares of Restricted Stock shall thereby be free of restrictions and be fully transferable. 8.11 TERMINATION OF EMPLOYMENT FOR OTHER REASONS. In the event that a Participant terminates his employment with the Company or any of its Subsidiaries for any reason other than for death, disability, or retirement (including early retirement), as set forth in Sections 8.9 and 8.10 herein, during the Period of Restriction, then any Shares of Restricted Stock still subject to restrictions as of the date of such termination shall automatically be forfeited and returned to the Company; provided, however, that in the event of a termination of the employment of a Participant by the Company or any of its Subsidiaries other than for Cause, the Committee, in its sole discretion (subject to Section 3.8 herein), may waive or modify the automatic forfeiture of any or all such Shares as it deems appropriate. ARTICLE 9 PERFORMANCE SHARES ------------------ 9.1 GRANT OF PERFORMANCE SHARES. Subject to the terms and provisions of the Plan, Performance Shares may be granted to Participants at any time and from time to time as shall be determined by the Committee. The maximum number of Shares that may be issued to any Participant in a calendar year shall not exceed two hundred fifty thousand (250,000), subject to adjustment as provided in Section 4.3. 9.2 VALUE OF PERFORMANCE SHARES. The Committee shall set performance goals over certain periods to be determined in advance by the Committee ("Performance Periods"). Prior to each grant of Performance Shares, the Committee shall establish an initial number of Shares for each Performance Share granted to each Participant for that Performance Period. Prior to each grant of Performance Shares, the Committee also shall set the performance goals that will be used to determine the extent to which the Participant receives a payment of the number of Shares for the Performance Shares awarded for such Performance Period. These goals will be based on the attainment by the Company or its Subsidiaries of certain objective performance measures, which may include, but are not limited to one or more of the following: total shareholder return, return on equity, return on capital, earnings per share, market share, stock price, sales, costs, net income, cash flow, retained earnings, results of customer satisfaction surveys, aggregate product price and other product price measures, safety record, service reliability, demand-side management (including conservation and load management), operating and maintenance cost management, and energy production availability performance measures. Such performance goals also may be based upon the attainment of specified levels of performance of the Company or one or more Subsidiaries under one or more of the measures described above, relative to the performance of 14 FirstEnergy Corp. Executive and Director Incentive Compensation Plan other corporations. The Committee may provide for the crediting of dividend equivalents during the performance period. With respect to each such performance measure utilized during a Performance Period, the Committee shall assign percentages to various levels of performance which shall be applied to determine the extent to which the Participant shall receive a payout of the number of Performance Shares awarded. With respect to Covered Employees, all performance goals shall be objective performance goals satisfying the requirements for "performance-based compensation" within the meaning of Section 162(m)(4) of the Code, and shall be set by the Committee within the time period prescribed by Section 162(m) of the Code and related regulations. 9.3 PAYMENT OF PERFORMANCE SHARES. After a Performance Period has ended, the holder of a Performance Share shall be entitled to receive the value thereof as determined by the Committee. The Committee shall make this determination by first determining the extent to which the performance goals set pursuant to Section 9.2 have been met. It will then determine the applicable percentage (which may exceed 100%) to be applied to, and will apply such percentage to, the number of Performance Shares to determine the payout to be received by the Participant. In addition, with respect to Performance Shares granted to any Covered Employee, no payout shall be made hereunder except upon written certification by the Committee that the applicable performance goal or goals have been satisfied to a particular extent. The amount payable in cash in a calendar year to any Participant with respect to any Performance Period pursuant to any Performance Share award shall not exceed $2,000,000. 9.4 COMMITTEE DISCRETION TO ADJUST AWARDS. Subject to Section 3.2 regarding Awards to Covered Employees, the Committee shall have the authority to modify, amend or adjust the terms and conditions of any Performance Share award, at any time or from time to time, including but not limited to the performance goals. 9.5 FORM AND TIMING OF PAYMENT. The payment described in Section 9.3 herein shall be made in cash, Stock, or a combination thereof as determined by the Committee. Payment may be made in a lump sum or installments as prescribed by the Committee. If any payment is to be made on a deferred basis, the Committee may provide for the payment of dividend equivalents or interest during the deferral period. Any stock issued in payment of a Performance Share shall be subject to the restrictions on transfer in Section 3.8 herein. 9.6 TERMINATION OF EMPLOYMENT DUE TO DEATH, DISABILITY, OR RETIREMENT (including early retirement). In the case of death, disability, or retirement (each of disability and retirement as defined under the established rules of the Company or any of its Subsidiaries, as the case may be), the holder of a Performance Share shall receive a prorated payment based on the Participant's number of full months of service during the Performance Period, further adjusted based on the achievement of the performance goals, as computed by the Committee. The Committee may require that a Participant have a minimum number of full months of service during the Performance Period to qualify for an Award payout. 9.7 TERMINATION OF EMPLOYMENT FOR OTHER REASONS. In the event that a Participant terminates employment with the Company or any of its Subsidiaries for any reason other than death, disability, or retirement (including early retirement), all Performance Shares shall be 15 FirstEnergy Corp. Executive and Director Incentive Compensation Plan forfeited; provided, however, that in the event of a termination of the employment of the Participant by the Company or any of its Subsidiaries other than for Cause, the Committee in its sole discretion may waive the automatic forfeiture provisions. 9.8 NONTRANSFERABILITY. No Performance Shares granted under the Plan may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution until the termination of the applicable Performance Period. All rights with respect to Performance Shares granted to a Participant under the Plan shall be exercisable during his/her lifetime only by such Participant. ARTICLE 10 CASH AWARDS ----------- 10.1 GRANT OF CASH AWARD. Subject to the terms of this Plan, Cash Awards may be made to Participants at any time and from time to time as shall be determined by the Committee. The Committee shall have complete discretion in the determining the form of the Cash Awards granted to Participants 10.2 CASH AWARD PERFORMANCE CRITERIA. All Cash Awards made under this Plan shall be subject to pre-established, objective, business-related Performance Measures. The performance measures shall be approved for use by the Committee and the Committee shall certify their attainment and the resulting payout of Cash Awards. Performance Measures for Cash Awards may be measurable for periods of one year to five years (allowing for prorated periods for new Participants). The Performance Measures may include, but shall not be limited to: operational measures (e.g. attaining merger milestones, customer satisfaction, service reliability, safety and tactical objectives), financial measures (e.g. expense control, revenue, margins and shareholder value added levels "SVA") and individual measures. Performance Measures can be made on overlapping cycles, (i.e. one-year cycles could emphasize operational measures and three-year cycles could emphasize SVA Performance Measures.) Each cycle of Performance Measures could have a distinct Cash Award associated with it. 10.3 PAYOUT OF CASH AWARDS. Payouts of Cash Awards are made in relationship to a target payout level determined prior to each cycle on a per Participant basis. Target levels under multiple cycles will be calibrated to provide, in total, an annualized level of incentives consistent with the Company's compensation philosophy as set by the Committee. Actual payouts of Cash Awards will vary with performance results as follows: actual payouts based upon operational or individual Performance Measures will vary from 50% (if threshold performance is attained) to 150% of the target level; actual payouts based upon Company SVA and other corporate financial measures will vary from 50% (if threshold performance is attained) up to 200% of the target level. The maximum Cash Award payable in a calendar year to any Participant with respect to any Performance Period shall not exceed $2,000,000. 10.4 CONVERSION OF CASH AWARD PAYOUT TO RESTRICTED STOCK. At the request of the Participant, but subject to the discretion of the Committee, any Cash Award payout may be converted to Restricted Stock at a discount. The conversion to Restricted Stock will occur by multiplying the Cash Award by a premium, but in no event more than 120% and dividing the 16 FirstEnergy Corp. Executive and Director Incentive Compensation Plan product by the Fair Market Value of the Restricted Stock on the date of conversion, which shall be chosen by the Committee at least 10 days in advance, to determine the number of shares of Restricted Stock that will be provided as full settlement of the Cash Award. The shares of Restricted Stock provided to Participants in settlement of Cash Awards shall be Restricted Stock subject to Article 8. Article 11 Directors' Awards ----------------- 11.1 GRANT OF DIRECTORS' AWARDS. In lieu of a portion of their retainer, Directors' Awards can be made in the form of Stock Options or Restricted Stock under Articles 6 and 8 respectively. No other Awards may be made to Directors under the Plan. 11.2 CONVERSION OF RETAINER TO STOCK. At the request of a Director but subject to the election of the Committee, a Director may convert any retainer otherwise due to be paid by the Company in cash to an aggregate equivalent value of either Stock Options, Restricted Stock or both. 11.3 CONVERSION OF RETAINER TO RESTRICTED STOCK. Retainer, otherwise payable in cash may be converted to Restricted Stock under Article 8. The conversion to Restricted Stock will occur by multiplying the retainer by a premium, but in no event more than 120% and dividing the product by the Fair Market Value of the Restricted Stock on the date of conversion, which shall be chosen by the Committee at least 10 days in advance, into the amount of the retainer to determine the number of shares of Restricted Stock that will be provided as full settlement of the retainer. 11.4 CONVERSION OF RETAINER TO STOCK OPTIONS. Retainer otherwise due to be paid in cash may be converted to Stock Options under Article 6 at the request of the Participant but subject to the election of the Committee. Retainer shall be converted by multiplying the retainer by a premium, but in no event more than 120% and dividing the product by the amount equal to the Black-Scholes Value of the Stock Option on the date of conversion. The quotient of which is the number of Stock Options that shall be awarded. ARTICLE 12 BENEFICIARY DESIGNATION ----------------------- Each Participant under the Plan may, from time to time, name any beneficiary or beneficiaries (who may be named contingently or successively and who may include a trustee under a will or living trust) to whom any benefit under the Plan is to be paid in case of his/her death before he receives any or all of such benefit. Each designation will revoke all prior designations by the same Participant, shall be in a form prescribed by the Committee, and will be effective only when filed by the Participant in writing with the Committee during his lifetime. In the absence of any such designation or if all designated beneficiaries predecease the Participant, benefits remaining unpaid at the Participant's death shall be paid to the Participant's estate. 17 FirstEnergy Corp. Executive and Director Incentive Compensation Plan ARTICLE 13 RIGHTS OF EMPLOYEES ------------------- 13.1 EMPLOYMENT. Nothing in the Plan shall interfere with or limit in any way the right of the Company or any of its Subsidiaries to terminate any Participant's employment at any time, nor confer upon any Participant any right to continue in the employ of the Company or any of its Subsidiaries. 13.2 PARTICIPATION. No employee shall have a right to be selected as a Participant, or, having been so selected, to be selected again as a Participant. 13.3 NO IMPLIED RIGHTS; RIGHTS ON TERMINATION OF SERVICE. Neither the establishment of the Plan nor any amendment thereof shall be construed as giving any Participant, beneficiary, or any other person any legal or equitable right unless such right shall be specifically provided for in the Plan or conferred by specific action of the Committee in accordance with the terms and provisions of the Plan. Except as expressly provided in this Plan, neither the Company nor any of its Subsidiaries shall be required or be liable to make any payment under the Plan. 13.4 NO RIGHT TO COMPANY ASSETS. Neither the Participant nor any other person shall acquire, by reason of the Plan, any right in or title to any assets, funds or property of the Company or any of its Subsidiaries whatsoever including, without limiting the generality of the foregoing, any specific funds, assets, or other property which the Company or any of its Subsidiaries, in its sole discretion, may set aside in anticipation of a liability hereunder. Any benefits which become payable hereunder shall be paid from the general assets of the Company or the applicable subsidiary. The Participant shall have only a contractual right to the amounts, if any, payable hereunder unsecured by any asset of the Company or any of its Subsidiaries. Nothing contained in the Plan constitutes a guarantee by the Company or any of its Subsidiaries that the assets of the Company or the applicable subsidiary shall be sufficient to pay any benefit to any person. ARTICLE 14 CHANGE IN CONTROL ----------------- 14.1 STOCK BASED AWARDS. Notwithstanding any other provisions of the Plan, in the event of a Change in Control, all Stock based awards granted under this Plan shall immediately vest 100% in each Participant (subject to Section 3.8 herein), including Incentive Stock Options, Nonqualified Stock Options, Stock Appreciation Rights, and Restricted Stock. 14.2 ALL AWARDS OTHER THAN STOCK BASED AWARDS. Notwithstanding any other provisions of the Plan, in the event of a Change in Control, all Awards other than Stock Based Awards granted under this Plan shall be immediately paid out in cash, including Performance Shares. The amount of the payout shall be based on the higher of: (i) the extent, as determined by the Committee, to which performance goals, established for the Performance Period then in progress have been met up through and including the effective date of the Change in Control or (ii) 100% of the value on the date of grant of the number of Performance Shares. 18 FirstEnergy Corp. Executive and Director Incentive Compensation Plan ARTICLE 15 AMENDMENT, MODIFICATION, AND TERMINATION ---------------------------------------- 15.1 AMENDMENT, MODIFICATION, AND TERMINATION. At any time and from time to time, the Board or Committee may terminate, amend, or modify the Plan. However, without the approval of the stockholders of the Company if required by the Code, by the insider trading rules of Section 16 of the Exchange Act, by any national securities exchange or system on which the Stock is then listed or reported, or by any regulatory body having jurisdiction with respect hereto, no such termination, amendment, or modification may: (a) Increase the total amount of Stock which may be issued under this Plan, except as provided in Section 4.3 herein; or (b) Change the class of Employees eligible to participate in the Plan; (c) Materially increase the cost of the Plan or materially increase the benefits to Participants; or (d) Extend the maximum period after the date of grant during which Options or Stock Appreciation Rights may be exercised. 15.2 AWARDS PREVIOUSLY GRANTED. No termination, amendment or modification of the Plan other than pursuant to Section 4.3 hereof shall in any manner adversely affect any Award theretofore granted under the Plan, without the written consent of the Participant. 15.3 DEFERRAL OF PAYMENTS AND DISTRIBUTIONS. Cash Awards pursuant to Article 10 may be eligible for deferral by any plan(s) offered by the company, subject to the approval of the Committee and any administrative requirements imposed by the Committee. ARTICLE 16 WITHHOLDING AND DEFERRAL ------------------------ 16.1 TAX WITHHOLDING. The Company and any of its Subsidiaries shall have the power and the right to deduct or withhold, or require a Participant to remit to the Company or any of its Subsidiaries, an amount sufficient to satisfy Federal, state and local taxes (including the Participant's FICA obligation) required by law to be withheld with respect to any grant, exercise, or payment made under or as a result of this Plan. 16.2 STOCK DELIVERY OR WITHHOLDING. With respect to withholding required upon the exercise of Stock Options, or upon the lapse of restrictions on Restricted Stock, participants may elect, subject to the approval of the Committee, to satisfy the withholding requirement, in whole or in part, by tendering to the Company Shares of previously acquired Stock or by having the Company withhold Shares of Stock, in each such case in an amount having a Fair Market Value equal to the amount required to be withheld to satisfy the tax withholding obligations described in Section 16.1. The value of the Shares to be tendered or withheld is to be based on the Fair Market Value of the Stock on the date that the amount of tax to be withheld is to be determined. All Stock withholding elections shall be irrevocable and made in writing, signed by the Participant on forms approved by the Committee in advance of the day that the transaction becomes taxable. 19 FirstEnergy Corp. Executive and Director Incentive Compensation Plan Stock withholding elections made by Participants who are subject to the short-swing profit restrictions of Section 16 of the Exchange Act must comply with the additional restrictions of Section 16 and Rule 16b-3 in making their elections. ARTICLE 17 SUCCESSORS ---------- All obligations of the Company under the Plan, with respect to Awards granted hereunder, shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation or otherwise, of all or substantially all of the business and/or assets of the Company. ARTICLE 18 REQUIREMENTS OF LAW ------------------- 18.1 REQUIREMENTS OF LAW. The granting of Awards and the issuance of Shares of Stock under this Plan shall be subject to all applicable laws, rules, and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required. 18.2 GOVERNING LAW. The Plan, and all agreements hereunder, shall be construed in accordance with and governed by the laws of the State of Ohio without giving effect to the principles of the conflicts of laws. 5 Plan, Rev 4.doc 05/21/02 20 EX-10 6 fe_ex10-31.txt EX. 10-4 DEFERRED COMP PLAN FOR OUTSIDE DIRECTORS REVISED NOV. 19, 2002 FIRSTENERGY CORP. DEFERRED COMPENSATION PLAN FOR OUTSIDE DIRECTORS 1. GENERAL 1.1 Preamble. The FirstEnergy Corp. Deferred Compensation Plan for -------- Outside Directors (the "Plan") was initially established on December 31, 1997 as the FirstEnergy Corp. Deferred Compensation Plan for Directors. The Ohio Edison Company Deferred Compensation Plan for Directors was merged into the Plan effective as of December 31, 1997 and the Centerior Energy Corporation Deferred Compensation Plan for Directors was merged into the Plan effective as of January 1, 2000. This restatement of the Plan is effective November 7, 2001 and supersedes all prior versions of this Plan and all prior arrangements and understandings regarding the deferral of fees by Directors. 1.2 Purpose. The purpose of this Plan is to provide a benefit to ------- Directors by giving them the opportunity to defer certain fees in accordance with the provisions of the Plan. The Plan is also intended to advance the interests of FirstEnergy Corp. and its Affiliates by providing a benefit which attracts and retains the services of qualified persons who are not employees of FirstEnergy Corp. or its Affiliates to serve as Directors. 1.3 Status under Laws. The Plan does not provide benefits to employees ----------------- of the Company or any Affiliate and, accordingly, is not subject to the provisions of the Employee Retirement Income Security Act. The Plan shall be unfunded for purposes of the Internal Revenue Code and is not intended to qualify under Internal Revenue Code Section 401(a). 1.4 Definitions. As used in the Plan, the following terms shall have ----------- the following meanings: (a) "Accounts" means bookkeeping accounts maintained on behalf of each Participant and includes a Participant's Deferred Fee Account, Transfer Account and such other accounts as may be established in accordance with the directions of the Committee. (b) "Administrator" means the Committee or such other person selected by the Board to administer the Plan. (c) "Affiliate" means a member of the affiliated group of corporations (as defined in Section 1504 of the Internal Revenue Code and the 1 regulations thereunder) that includes the Company which elects to participate in this Plan in accordance with Section 9.4 and whose participation is approved by the Company. (d) "Appeals Committee" means the committee appointed by the Board to review claims denied by the Committee and to have such other discretionary powers and duties as provided by Section 8.3. (e) "Beneficiary" means one or more persons, trust, estates or other entities, designated in accordance with Article 5, that are entitled to receive benefits under this Plan upon the death of a Participant. A Beneficiary is a general unsecured creditor of the Company or of the Affiliate which maintains the Accounts and provides any benefits under this Plan. (f) "Board" means the board of directors of the Company. (g) "Bonus Credit" means an amount credited to a Participant's Account as provided in Section 3.5(b)(1). (h) "Change in Control" means any of the following: (1) The acquisition by any Person (as such term is used in Section 13(d) or 14(d) of the Securities Exchange Act of 1934 (the "Exchange Act"), as amended) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act)of fifty percent (50%) or more (twenty five percent (25%) if such Person proposes any individual for election to the Board or any member of the Board is a representative of such Person) of either (i) the then outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or (ii) the combined voting power of the then outstanding voting securities of the Company (the "Outstanding Company Voting Securities); provided, however, that the following acquisitions shall not constitute a Change in Control: (i) any acquisition directly from the Company (excluding an acquisition by virtue of the exercise of a conversion privilege); (ii) any acquisition by the Company; (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company; or (iv) any acquisition by any corporation pursuant to a reorganization, merger or consolidation (collectively "Reorganization") if, following such Reorganization the conditions described in 2 clauses (i), (ii), and (iii) of paragraph (3) of this Subsection (h) are satisfied; or (2) Individuals who, as of the date hereof, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of either an actual or threatened election contest (as such terms are used in Rule 14a 11 of Regulation 14A promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consent by or on behalf of a Person other than the Board; or (3) Approval by the shareholders of the Company of a Reorganization, unless, following such Reorganization (i) more than seventy-five percent (75%) of, respectively, the then outstanding shares of common stock of the corporation resulting from such Reorganization and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Reorganization in substantially the same proportions as their ownership, immediately prior to such Reorganization of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) no Person (excluding the Company, any holding company formed by the Company to become the parent of the Company, any employee benefit plan (or related trust) of the Company or such corporation resulting from such Reorganization and any Person beneficially owning, immediately prior to such Reorganization directly or indirectly, twenty-five percent (25%) or more of, respectively, the Outstanding Company Common Stock, or Outstanding Voting Securities, as the case may be) beneficially owns, directly or indirectly, twenty-five percent (25%) or more of, respectively, the then 3 outstanding shares of common stock of the corporation resulting from such Reorganization or the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Reorganization were members of the Incumbent Board at the time of the execution of the initial agreement providing for such Reorganization; or (4) Approval by the shareholders of the Company of (i) a complete liquidation or dissolution of the Company or (ii) the sale or other disposition of all or substantially all of the assets of the Company, other than to a corporation, with respect to which following such sale or other disposition, (A) more than seventy-five percent (75%) of, respectively, the then outstanding shares of common stock of such corporation and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such sale or other disposition in substantially the same proportion as their ownership, immediately prior to such sale or other disposition, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (B) no Person (excluding the Company, any holding company formed by the Company to become the parent of the Company and any employee benefit plan (or related trust) of the Company or such corporation and any Person beneficially owning, immediately prior to such sale or other disposition, directly or indirectly, twenty-five percent (25%) or more of the Outstanding Company Common Stock or Outstanding Company Voting Securities, as the case may be) beneficially owns, directly or indirectly, twenty-five percent (25%) or more of, respectively, the then outstanding shares of common stock of such corporation and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors and (C) at least a majority of the members of the board of directors of such corporation were members of the Incumbent Board at the time of the execution of the initial agreement or 4 action of the Board providing for such sale or other disposition of assets of the Company. A Change in Control may occur only with respect to the Company. A change in ownership of common stock of an Affiliate or subsidiary, change in membership of a board of directors of an Affiliate or subsidiary, the sale of assets of an Affiliate or subsidiary, or any other event described in this Subsection (h) that occurs only with respect to an Affiliate or subsidiary does not constitute a Change in Control. (i) "Committee" means the Compensation Committee of the Board. (j) "Company" means FirstEnergy Corp. (k) "Corporate Secretary" means the Corporate Secretary of FirstEnergy Corp. (l) "Default" means a failure by the Company or Affiliate to contribute to the Trust, within thirty (30) days of receipt of written notice from its trustee, any of the following amounts: (1) The full amount of any insufficiency in assets of the Trust or any subtrust of the Trust that is required to pay any Plan benefit payable by the trustee pursuant to directions by the Committee or disputed by the Committee after a Special Circumstance and determined by the trustee to be payable; or (2) Any contribution which is then required to be made by the Company or Affiliate to the Trust or any subtrust of the Trust. If, after the occurrence of a Default, the Company or Affiliate at any time cures such Default by contributing to the Trust all amounts which are then required under paragraphs (1) and (2) above, it shall then cease to be deemed that a Default has occurred or that a Special Circumstance has occurred by reason of such Default. (m) "Deferred Fee Account" means a bookkeeping account established by the Company or a Affiliate which maintains record of deferred Director's Fees including expenses and earnings. All amounts credited to a Director's Deferred Fee Account shall constitute a general, unsecured liability of the Company or of the Affiliate for which the Director serves when Director's Fees are deferred. 5 (n) "Deferred Stock Fund" means an Investment Fund which is deemed to be invested in FirstEnergy Corp. common stock. (o) "Director" means a member of the Board, a member of the board of directors of any Affiliate and any individual designated as a Director by the committee incident to a merger of or acquisition by the Company of an Affiliate. A Director may not be an employee of the Company or any Affiliate. (p) "Director's Fees" means the equity retainer fees, cash retainer fees, meeting fees, and chairperson fees payable for services as a Director whether payable in cash or in equity instruments. (q) "Disability" means a period of disability during which the Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or which has lasted or can be expected to last for a continuous period of not less than twelve (12) months or such other period of disability as defined in Internal Revenue Code Section 22(e)(3). A Participant shall not be considered to be Disabled unless he or she furnishes proof of the existence of Disability in the form and manner as required by the Committee. (r) "Investment Fund" means an investment fund in which Accounts may be deemed to be invested. An Investment Fund may be any open-ended fund, closed-end fund, a fund which is deemed to be invested in a particular stock or other investment, or a fund which credits a fixed or variable interest rate determined by the Committee. (s) "Participant" means a Director or former Director who is owed a benefit under this Plan. A Participant is a general unsecured creditor of the Company or of the Affiliate which maintains the Accounts and provides any benefits under this Plan. (t) "Plan" means the FirstEnergy Corp. Deferred Compensation Plan for Outside Directors. (u) "Plan Year" means the period beginning on each January 1 and ending on the following December 31. (v) "Potential Change in Control" means any of the following: (1) Any Person (as defined in Section 13(d)(3) of the Exchange Act) other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, 6 delivers to the Company a statement containing the information required by Schedule 13 D under the Exchange Act, or any amendment to any such statement (or the Company becomes aware that any such statement or amendment has been filed with the Securities and Exchange Commission pursuant to applicable Rules under the Exchange Act), that shows that such Person has acquired, directly or indirectly, the beneficial ownership of (i) more than twenty percent (20%) of any class of equity security of the Company entitled to vote as single class in the election or removal from office of directors, or (ii) more than twenty percent (20%) of the voting power of any group of classes of equity securities of the Company entitled to vote as a single class in the election or removal from office of directors; (2) The Company becomes aware that preliminary or definitive copies of a proxy statement and information statement or other information have been filed with the Securities and Exchange Commission pursuant to Rule 14a-6, Rule 14c-5, or Rule 14f-1 under the Exchange Act relating to a Potential Change in Control of the Company; (3) Any Person delivers to the Company pursuant to Rule 14d-3 under the Exchange Act a Tender Offer Statement relating to Voting Securities of the Company (or the Company becomes aware that any such statement has been filed with the Securities and Exchange Commission pursuant to applicable Rules under the Exchange Act); (4) Any Person (other than the Company) publicly announces an intention to take actions which if consummated would constitute a Change in Control; (5) The Company enters into an agreement or arrangement, the consummation of which would result in the occurrence of a Change in Control; (6) The Board approves a proposal, which if consummated would constitute a Change in Control; or (7) The Board adopts a resolution to the effect that, for purposes of this Trust Agreement, a Potential Change in Control has occurred. 7 Notwithstanding the foregoing, a Potential Change in Control shall not be deemed to occur as a result of any event described in paragraphs (1) through (6) above, if a number of directors (who were serving on the Board immediately prior to such event and who continue to serve on the Board) equal to a majority of the members of the Board as constituted prior to such event determines that the event shall not constitute a Potential Change in Control. If a Potential Change in Control ceases to exist for any reason except for the occurrence of a Change in Control, it shall then cease to be deemed that a Potential Change in Control has occurred as a result of any event described in paragraphs (1) through (7) above, or that a Special Circumstance has occurred by reason of such Potential Change in Control. A Potential Change in Control may occur only with respect to the Company. A change in ownership of common stock of an Affiliate or subsidiary, change in membership of a board of directors of an Affiliate or subsidiary, the sale of assets of an Affiliate or subsidiary, or any other event described in this Subsection (v) that occurs only with respect to an Affiliate or subsidiary does not constitute a Change in Control. (w) "Retirement" means severance of all directorships with the Company and all Affiliates by a Participant on or after the attainment of age sixty-nine (69) or at such earlier age as approved by the Committee. (x) "Separation" means severance of all directorships with the Company and all Affiliates by a Participant. (y) "Special Circumstance" means a Change in Control, a Potential Change in Control, or a Default. (z) "Transfer Account" means a bookkeeping account established by the Company or an Affiliate which maintains record of deferred Directors' Fees transferred from another plan including expenses and earnings. All amounts credited to a Directors' Transfer Account shall constitute a general, unsecured liability of the Company or of the Affiliate for which the Director serves. (aa)"Trust" means the FirstEnergy Corp. Trust for Outside Directors. (bb)"Year of Service" means a period of time commencing on a date during a calendar year and ending on the day immediately preceding such date in the subsequent calendar year throughout which an individual serves as a Director. A Year of Service shall 8 commence for specified purposes such as vesting of the Bonus Credit under Section 3.5(b)(2) on the date as set forth in the Plan. 2. DEFERRALS 2.1 Written Election to Defer Fees. Any Director may elect from time ------------------------------ to time, by written notice to the Company given on or before December 31 of any year, to defer receipt of all or any specified part of his or her Director's Fees earned for services performed during the calendar years following his or her election to defer. 2.2 Election During First Year of Becoming a Director. Any person who ------------------------------------------------- becomes a Director and who was not a Director on the preceding December 31 may elect, by written notice to the Company given within thirty (30) days after becoming a Director, to defer receipt of all or any specified part of his or her Director's Fees earned for services performed during the balance of the calendar year following his or her election to defer and during succeeding calendar years. 2.3 Election Irrevocable. An election to defer Director's Fees shall -------------------- be irrevocable and shall continue from year to year unless the Director terminates it by written notice to the Company on or before December 31 of the year preceding the calendar year to which the termination applies. 2.4 Transfers from Other Plans. If permitted by the Committee and the --- -------------------------- provisions of this Plan, a Director may transfer his or her benefits from another nonqualified plan to this Plan as provided in this Section. (a) An individual who was a member of a board of directors of a --- corporation which is merged into the Company, who was not an employee of such corporation, who is not an employee of the Company or any Affiliate, and who is either selected to serve as a member of the Board or designated as a Director with respect to the Company for purposes of this Plan by the Committee may elect to transfer his or her benefit under a nonqualified plan sponsored by the corporation merged into the Company. Any account balance transferred shall be credited to a Transfer Account established and maintained under this Plan and shall be a liability of the Company. Any other benefit transferred shall be identified in Attachment 2.4. (b) An individual who was a member of a board of directors of a --- corporation which is merged into a Affiliate or which is acquired and becomes a Affiliate, who was not an employee of such corporation, who is not an employee of the Company or any Affiliate and who is either a member of the board of directors of a Affiliate after such merger or acquisition or designated as a 9 Director with respect to an Affiliate for purposes of this Plan by the Committee may elect to transfer his or her benefit under a nonqualified plan sponsored by the corporation merged into an Affiliate or acquired by the Company. Any account balance transferred shall be credited to a Transfer Account established and maintained under this Plan and shall be a liability of the Affiliate into which the corporation is merged or which the corporation becomes. Any other benefit transferred shall be identified in Attachment 2.4. (c) Any balance transferred shall become payable under the terms --- and conditions of this Plan; provided however, that the Director's deferral elections, commencement date elections, and beneficiary elections made under the plan from which the benefit is transferred shall continue to be effective under this Plan unless such elections are amended or changed under the terms of this Plan. (d) Provisions regarding such transfers shall be established by --- the Committee and shall be set forth in Attachment 2.4 of this Plan. 3. ACCOUNTS AND INVESTMENT FUNDS 3.1 Deferred Fee Account. Any Director's Fees earned and deferred -------------------- while serving as a member of the Board shall be credited by the Company to the Participant's Deferred Fee Account established and maintained by the Company as of the date the Director's Fees would otherwise be payable. Any Director's Fees earned while serving as a member of the board of directors of a Affiliate shall be credited by the Affiliate to the Participant's Deferred Fee Account established and maintained by such Affiliate as of the date the Director's Fees would otherwise be payable. 3.2 Transfer Account. Any account balances transferred to this Plan ---------------- pursuant to Section 2.4 shall be credited to the Participant's Transfer Account established and maintained by the Company or the applicable Affiliate. 3.3 Other Accounts and Subaccounts. The Committee may establish such ------------------------------ other Accounts and subaccounts as it may deem necessary for the administration of the Plan including subaccounts where the Participant has specified different methods of payment, or where necessary to maintain the vested portion of a Participant's Account. Such Accounts and subaccounts shall be credited in accordance with procedures adopted by the Committee. 3.4 Investment Funds. A Participant's Accounts shall be adjusted for ---------------- gains and losses as if the Accounts held assets and such assets were invested in one or more Investment Funds selected by the Committee. The Investment Funds in which a Participant is deemed to be invested shall be determined in accordance with Section 3.5. The Committee shall 10 have sole discretion in the selection, number and types of Investment Funds for this Plan and may change or eliminate Investment Funds from time to time in its sole discretion. 3.5 Credits to Investment Funds. The Committee shall credit Director's --------------------------- Fees deferred under this Plan and transferred from another plan to Investment Funds in accordance with this Section unless other rules for transferred amounts are set forth in Attachment 2.4. (a) Rules and Limitations Regarding Deferrals and Transfers. (1) Equity Retainer Fees and Transfers Distributable only in Stock. Equity retainer fees that are deferred under this Plan and any account balance transferred directly to this Plan from another plan in accordance with Section 2.4 where such account balance may only be distributed in stock from the other plan upon an event permitting distribution and such stock has been or is to be exchanged for common stock of FirstEnergy Corp. under a plan of merger with the Company shall be credited to the Deferred Stock Fund. (2) All Other Deferred Director's Fees and Transfers. Unless and until another procedure is established by the Committee for designation of Investment Funds, a Participant may direct that all deferred Director's Fees and transfers except those Director's Fees and transfers identified in Section 3.5(a)(1) shall be deemed to be invested in any one or more of the Investment Funds selected by the Committee. In the event a Participant does not direct the Investment Funds in which his or her Accounts are deemed to be invested, the deferrals and transfers shall be deemed to be invested in an Investment Fund that reflects the investment performance of a money market fund selected by the Committee. (b) Rules and Limitations Regarding Bonus Credit. (1) Bonus Credit. At the time Director's Fees except equity retainer fees are initially deferred under this Plan and credited for investment into the Deferred Stock Fund, the amount of cash retainer fees, meeting fees or chairperson fees credited to the Deferred Stock Fund shall be increased by a Bonus Credit equal to twenty percent (20%) of such Director's Fees credited to the Deferred Stock Fund. Any account balance transferred to this Plan from another plan in accordance with Section 2.4 that may be credited to the Deferred Stock Fund shall not be increased by the Bonus Credit. 11 (2) Vesting of Bonus Credit. A Participant shall be fully vested in his or her Bonus Credit if he or she has three (3) Years of Service from the date the Bonus Credit is credited to the Participant's Account. In addition, a Participant shall be fully vested in his or her Bonus Credit if he or she incurs a Separation upon death, Retirement, or Disability. Furthermore, a Participant shall be fully vested in the Bonus Credit and all associated earnings upon a Special Circumstance. (3) Forfeiture of Bonus Credit. If a Participant incurs a Separation, takes an accelerated distribution under Section 4.3 or withdraws a portion of his Accounts under Section 4.4, and the Bonus Credit has not been credited to the Deferred Stock Fund for a minimum of three (3) Years of Service from the date of crediting such amount to the Account until the date of Separation, accelerated distribution or withdraw, the Director shall forfeit all Bonus Credits not fully vested in accordance with Section 3.5(b)(2) (c) Rules and Limitations Regarding Transfers Among Investment Funds. (1) Deferred Stock Fund. No amount credited to the Deferred Stock Fund may be transferred and credited to any other Investment Fund, and no amount credited to an Investment Fund other than the Deferred Stock Fund may be transferred and credited to the Deferred Stock Fund. (2) All Other Investment Funds. Any amount credited to an Investment Fund other than the Deferred Stock Fund may be transferred and credited to any other Investment Fund except the Deferred Stock Fund at the direction of the Participant. (d) Investment Fund Performance. The earnings and losses of each Investment Fund shall be determined by the Committee, in its reasonable discretion, based on the performance of the Investment Funds themselves. The balance of a Participant's Accounts shall be credited or debited on a daily basis based on the performance of each Investment Fund in which a Participants' Accounts are deemed to be invested, such performance and the crediting of such performance being determined by the Committee in its sole discretion. 12 (e) Committee Procedures. The Committee may establish such rules and procedures as it determines to be appropriate for the crediting of deferrals and transfers to Investment Funds, for transfers among Investment Funds and for crediting earnings and losses of an Investment Fund. 3.6 Reporting. The Company shall provide a statement to each Director --------- who has any amount credited to his or her Accounts at least annually. 4. PAYMENT TO DIRECTOR 4.1 Distribution Payment. A Participant's Accounts shall be paid to -------------------- the Participant in cash, either in a lump sum or in annual installments over a period not to exceed ten (10) years except that payment of the balance of the Deferred Stock Fund to the Director shall be paid in the form of FirstEnergy Corp. common stock. 4.2 Distribution Election. A Participant's Accounts shall be ---------------------- distributed upon Retirement, Disability or other Separation in accordance with the elections on file with the Committee. (a) Initial Distribution Election. A Participant, in connection with his or her commencement of participation in the Plan, shall select the form of distribution payment to be made by the Plan. (b) Distribution Election of Transfer Amounts. Any elections made with respect to benefits transferred from another nonqualified plan shall be paid and distributed in accordance with the elections made by the Participant under such plan and such election shall continue to be in effect under this Plan unless the Participant submits new elections to the Committee under the provisions and procedures of this Plan. (c) Amendment of Distribution Election. A Participant may change his or her distribution election by filing a new superseding designation with the Company at any time prior to the 120 day period ending on the day prior to the day on which the Participant is entitled to distribution under this Plan. If a Participant requests any change in the date of the distribution of his Deferred Stock Fund, the request must be approved by the Committee. (d) Time of Payment. Payment(s) shall be made on or commencing with the January 1 next following the day the Participant ceases to be a Director unless prior to the 120 day period ending on the day prior to the day on which the Participant is entitled to distribution under this Plan, the Participant designates a later payment or 13 commencement date (not later than the January 1 next following the day he or she attains age 72, or his date of Retirement if later). 4.3 Accelerated Distribution. A Participant may at any time request an ------------------------ accelerated distribution of his or her Accounts, subject to a ten percent (10%) penalty and, if applicable, forfeiture of the Bonus Credit and associated deemed earnings described above if the Bonus Credit is not fully vested as provided by Section 3.5(b)(3). The ten percent (10%) penalty is imposed after any forfeiture of the Bonus Credit and associated deemed earnings. Such a request must be made in writing, in a form and manner specified by the Committee. If the request is approved by the Committee, the Company will distribute to the Participant the entire balance of his or her Accounts minus any forfeitures and minus the ten percent (10%) penalty as a lump sum within ninety (90) days after the end of the month in which the Committee receives the request. Such distribution shall completely discharge the Company and the applicable Affiliate from all liability with respect to the Participant's Accounts. If the Participant is an active Director, the Participant may not resume any further deferrals into the Plan until January 1 of the second calendar year following the calendar year in which the Director receives such distribution. 4.4 Withdrawal. A Participant who has deferred Director's Fees under ---------- this Plan for five (5) full years may request to withdraw a portion of the amounts credited to his or her Accounts subject to forfeiture of the Bonus Credit and associated deemed earnings and losses as provided by Section 3.5(b)(3). The requisite full years of deferral to request a withdrawal need not be consecutive but may be intermittent. Amounts credited to the Deferred Stock Fund will be distributed only after amounts credited to all other Investment Funds are distributed. Such request must be made in writing in a form and manner specified by the Committee and must specify the amount to be withdrawn and the future date or dates to be paid. The date(s) must be the first of a month in the second calendar year following the calendar year in which the request was made. The request will be irrevocable after December 31 of the calendar year in which it is made unless, prior to payment, the Participant separates from the Board or the board of directors of an Affiliate, or a Special Circumstance occurs. In these instances, the request will become null and void and the Account Balance will be paid as elected by the Participant pursuant to Section 4.2 or as provided in Section 4.5. If the request is approved by the Committee, the Company will distribute to the Director the balance of his or her Accounts except the portion credited to the Deferred Stock Fund as a lump sum within ninety (90) days after the end of the month in which the Committee receives the request and will distribute to the Director the balance of his or Accounts credited to the Deferred Stock Fund minus any forfeitures in FirstEnergy Corp. common stock in an administratively reasonable period of time. 4.5 Special Circumstance. In the instance of a Special Circumstance, -------------------- all balances in Investment Funds other than the Deferred Stock Fund shall be paid out immediately in cash as a lump sum and the balance of the Deferred Stock Fund shall be distributed in FirstEnergy Corp. common stock in an administratively reasonable period of time. A Participant may elect to receive distribution from this Plan in a distribution payment otherwise permitted by this Plan if such election is made more than 120 days prior to the Special Circumstance. 14 5. BENEFICIARY 5.1 Beneficiary Designation. Each Participant shall have the right, at ----------------------- any time, to designate his or her Beneficiary(ies) to receive any benefits payable under the Plan upon the death of a Participant. A Participant shall designate his or her Beneficiary by completing and signing a Beneficiary designation form and returning it to the Committee. The Participant shall also designate the time and the manner of payment to the Beneficiary, which may be either (i) in a lump sum as soon as practicable after the date of death, (ii) in a lump sum on January 1 of the year following the year in which the death occurred or (iii) in one or more annual payments the last of which may occur no later than January 1 of the fifth year following the year in which the death occurred. Amounts credited to the Deferred Stock Fund shall be distributed in FirstEnergy Corp. common stock in an administratively reasonable period of time. In the event the Participant designates distribution in the form of two or more annual payments, a pro rata portion shall be distributed from each Investment Fund in which the Participant's Accounts are credited. 5.2 Change of Beneficiary. A Participant shall have the right to file --------------------- a new Beneficiary designation form. Upon acceptance of a new Beneficiary designation form, all Beneficiary designations previously filed shall be cancelled as of the date of the new Beneficiary designation form. 5.3 Payment of Benefit upon Death. Upon the death of a Participant ----------------------------- prior to the distribution of the entire balance credited to the Participant's Accounts shall be paid to the Beneficiary or Beneficiaries designated by the Participant in writing filed with the Committee. In the event that a Participant fails to designate a Beneficiary or, if all designated Beneficiaries predecease the Participant or die prior to complete distribution of the Participant's benefits, then the Participant's benefits under this Plan shall be distributed to his or her surviving spouse. If the Participant has no surviving spouse, the benefits remaining under the Plan to be paid shall be paid to the executor or personal representative of the Participant's estate. 6. ASSIGNMENT Except to the extent that a Participant may designate a Beneficiary to receive any payment to be made following his or her death and except by will or the laws of descent and distribution, no rights or benefits under this Plan shall be assignable or transferable, or subject to encumbrance or charge of any nature. 7. ADMINISTRATION 7.1 Administration by Committee. Unless another Administrator is --------------------------- selected by the Board, this Plan shall be administered by the Committee. Except as otherwise provided by action of the Board or the terms of the Plan: (a) a majority of the members of the Committee shall constitute a quorum for the transaction of business, and (b) all resolutions or other actions taken by the Committee at a meeting shall be by the vote of the majority of the Committee 15 members present, or, without a meeting, by an instrument in writing signed by all members of the Committee. A Committee member may not vote on any matter which directly affects only his or her benefit under the Plan. 7.2 Powers of Administrator. The Administrator shall have the full ----------------------- discretion and authority to administer the Plan including the discretion and authority to construe, interpret, and apply this Plan, and to render nondiscriminatory rulings or determinations. All questions regarding the Plan, as well as any dispute over accounting or administrative procedures or interpretation of the Plan, shall be resolved at the sole discretion of the Administrator. Constructions, interpretations, and decisions of the Committee shall be conclusive and binding on all persons. The Administrator shall also have the discretion and authority to make, amend, interpret, and enforce all appropriate rules and regulations for the administration of this Plan. Any individual serving on the Committee who is a Participant shall not vote or act on any matter relating solely to himself or herself. When making a determination or calculation, the Committee shall be entitled to rely on information furnished by a Participant or the Company. 7.3 Delegation. The Committee may delegate all or any duties, ---------- discretions and responsibilities under this Plan to the Corporate Secretary. 8. CLAIMS 8.1 Any Participant or Beneficiary of a deceased Participant (such Participant or Beneficiary being referred to below as a "Claimant") may deliver to the Committee a written claim for a determination with respect to the amounts distributable to such Claimant from the Plan. If such a claim relates to the contents of a notice received by the Claimant, the claim must be made within sixty (60) days after such notice was received by the Claimant. All other claims must be made within 180 days of the date on which the event that caused the claim to arise occurred. The claim must state with particularity the determination desired by the Claimant. 8.2 The Committee shall consider a Claimant's claim within a reasonable time, but no later than ninety (90) days after receiving the claim. If the Committee determines that special circumstances require an extension of time for processing the claim, written notice of the extension shall be furnished to the Claimant prior to the termination of the initial ninety (90) day period. In no event shall such extension exceed a period of ninety (90) days from the end of the initial period. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Committee expects to render the benefit determination. The Committee shall notify the Claimant in writing: (a) that the Claimant's requested determination has been made, and that the claim has been allowed in full; or (b) that the Committee has reached a conclusion contrary, in whole or in part, to the Claimant's requested determination, and such notice must set forth in a manner calculated to be understood by the Claimant: 16 (1) the specific reason(s) for the denial of the claim, or any part of it; (2) specific reference(s) to pertinent provisions of the Plan upon which such denial was based; (3) a description of any additional material or information necessary for the Claimant to perfect the claim, and an explanation of why such material or information is necessary; and (4) an explanation of the claim review procedure set forth in Section 8.3 below. 8.3 Review of Denied Claim. The Board shall appoint the members of a ----------------------- Appeals Committee which shall consist of three (3) or more members. The Appeals Committee shall decide appeals of application denials as provided in this Section, have such other discretionary powers and authorities as provided by this Section, and shall have such other discretionary powers and duties as shall from time to time be assigned to the Appeals Committee by the Company. Prior to a Change in Control the members of the Appeals Committee shall remain in office at the will of the Board, and the Board may remove any of said members, from time to time, with or without cause. A member of the Appeals Committee may resign upon written notice to the remaining member or members of the Appeals Committee and to the Company respectively. The fact that a person is a prospective Participant, a Participant or a former Participant shall not disqualify him from acting as a member of the Appeals Committee. In case of the death, resignation or removal of any member of the Appeals Committee, the remaining members shall act until a successor-member is appointed. Upon request, the Company shall notify the Committee in writing of the names of the original members of the Appeals Committee, of any and all changes in the membership of the Appeals Committee, of the member designated as Chairman and the member designated as Secretary, and of any changes in either office. Until notified of a change, the Committee shall be protected in assuming that there has been no change in the membership of the Appeals Committee or the designation of Chairman or of Secretary since the last notification was filed with it. The Committee shall be under no obligation at any time to inquire into the membership of the Appeals Committee or its officers. All communications to the Appeals Committee shall be addressed to its secretary at the address of the Company. On or before sixty (60) days after receiving a notice from the Committee that a claim has been denied, in whole or in part, a Claimant (or the Claimant's duly authorized representative) may file with the Appeals Committee a written request for a review of the denial of the claim. The Claimant (or the Claimant's duly authorized representative): (a) may, upon request and free of charge, have reasonable access to, and copies of, all documents, records and other information relevant to the claim for benefits; (b) may submit written comments or other documents; and/or 17 (c) may request a hearing, which the Appeals Committee, in its sole discretion, may grant. 8.4 Decision on Review. The Appeals Committee shall render its -------------------- decision on review promptly, and no later than sixty (60) days after the Appeals Committee receives the Claimant's written request for a review of the denial of the claim. If the Appeals Committee determines that special circumstances require an extension of time for processing the claim, written notice of the extension shall be furnished to the Claimant prior to the termination of the initial sixty (60) day period. In no event shall such extension exceed a period of sixty (60) days from the end of the initial period. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Appeals Committee expects to render the benefit determination. In rendering its decision, the Appeals Committee shall take into account all comments, documents, records and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The decision must be written in a manner calculated to be understood by the Claimant, and it must contain: (a) specific reasons for the decision; and (b) specific reference(s) to the pertinent Plan provisions upon which the decision was based; and (c) an explanation of the claim review procedure set forth in the Trust. 9. AMENDMENT, TERMINATION AND PARTICIPATION 9.1 Amendment by Board. Prior to a Special Circumstance, the Board may ------------------ from time to time, amend, suspend, terminate or reinstate any or all of the provisions of this Plan, except that no amendment, suspension, termination or reinstatement shall adversely affect the Accounts or benefits under this Plan of any Participant as they existed immediately before the amendment, suspension, termination, merger or reinstatement or the manner of payments, unless the Participant shall have consented in writing. 9.2 Termination by the Company. Prior to a Special Circumstance, the -------------------------- Board may at any time terminate this Plan and/or transfer its liabilities under this Plan to a similar plan it may establish. Upon the termination of this Plan, amounts credited to the Accounts of Participants and benefits transferred shall continue to be payable to those Participants in accordance with the terms of this Plan. Upon termination of this Plan, if the Board should transfer its liabilities to another plan, such transfer of liabilities shall not adversely affect the Accounts or benefits of any Participant as they existed immediately prior to a transfer authorized by the Board or the manner of payments, unless the Participant shall have consented in writing. In addition, any transfer of liabilities of this Plan shall not affect the liability of the Company or any Affiliate responsible to pay the benefit represented by the Account Balance. 18 9.3 Effect of Plan Termination. Notwithstanding any other provisions -------------------------- of the Plan, if the Plan is terminated, no subsequent Director's fees may be deferred under this Plan. Upon termination, if the liabilities of this Plan are not transferred to another plan, the Director's Accounts shall continue to be credited with deemed earnings as provided in Section 3.4, and the entire balance in the Account Balance shall become payable to the Participant in accordance with the provisions of this Plan in effect at the date of termination. 9.4 Participation by Affiliates. Affiliates may participate in this --------------------------- Plan as provided in this Section. (a) A member of the affiliated group of corporations (as defined in Section 1504 of the Internal Revenue Code and the regulations thereunder) that includes the Company may adopt this Plan with the consent of the Company. The Affiliate shall be liable for the payment of any benefit of a Participant whose benefits under the Plan relate to Director's Fees deferred while serving on the board of directors of the Affiliate or which are transferred to this Plan by the Participant. Neither the Company nor any other Affiliate shall have any liability for such benefits. (b) Each Affiliate, by adopting the Plan, appoints the Company as its agent and fully empowers the Company to act on behalf of all Affiliates as it may deem appropriate in maintaining or terminating the Plan. The adoption by the Company of any amendment to the Plan or the termination of all or any part of the Plan will constitute and represent, without further action on the part of any Affiliate, the approval, adoption, ratification or confirmation by each Affiliate of any such amendment or termination and each Affiliate shall be bound by such amendment or termination. (c) An Affiliate may cease participation in the Plan only upon approval by the Company and only in accordance with such terms and conditions that may be required by the Company. 10. UNFUNDED PLAN 10.1 Bookkeeping Entries. The Accounts maintained for purposes of this ------------------- Plan shall constitute bookkeeping records of the Company or the applicable Affiliate and shall not constitute any allocation of any assets of the Company or Affiliate or be deemed to create any trust or special deposit with respect to any of the assets of the Company or any Affiliate. Neither the Company nor any Affiliate shall be under any obligation to any Participant to acquire, segregate or reserve any funds or other assets for purposes relating to this Plan. No Participant shall have any rights whatsoever in or with respect to any funds or other assets owned or held by the Company or any Affiliate. The rights of an Participant under this Plan are solely those of a 19 general creditor of the Company or any Affiliate to the extent of the amount credited to his or her Accounts with the Company or the applicable Affiliate and this Plan is a mere promise to pay benefits to the Participants. 10.2 Trusts, Insurance Contracts or Other Investment. The Company or ------------------------------------------------ the Affiliates may, in their respective discretion, establish one or more trusts, purchase one or more insurance contracts or otherwise invest or segregate funds for purposes relating to this Plan, but the assets of such trusts, rights and assets of such insurance contracts or otherwise invested or held in segregated funds shall at all times remain subject to the claims of the general creditors of the Company and any Affiliate as provided in such trust or contract except to the extent and at the time any payment is made to an Participant under this Plan. 11. MISCELLANEOUS 11.1 Severability. The invalidity or unenforceability of any ------------ particular provision of this Plan shall not affect any other provision, and the Plan shall be construed in all respects as if invalid or unenforceable provisions were omitted. 11.2 Applicable Law. This Plan shall be construed and governed in --------------- accordance with the laws of the State of Ohio without giving effect to principles of conflicts of laws. 11.3 Not a Contract. The terms and conditions of this Plan shall not -------------- be deemed to constitute a contract for services between the Company or any Affiliate and the Participant. A Director is retained on an "at will" relationship that can be terminated at any time for any reason, or no reason, with or without cause, and with or without notice, unless expressly provided in a written agreement. Nothing in this Plan shall be deemed to give a Participant the right to be retained as a Director of the Company and any Affiliate. 11.4 Successors. The provisions of this Plan shall bind and inure to ---------- the benefit of the successors and assigns of the Company and each Affiliate. 11.5 Distribution in the Event of Taxation. If the Trust terminates in ------------------------------------- accordance with its terms and benefits are distributed from the Trust to a Participant in accordance therewith, the Participant's benefits under this Plan shall be reduced to the extent of such distributions. (a) If, for any reason, all or any portion of a Participant's benefits under this Plan becomes taxable to the Participant prior to receipt, a Participant may petition the Committee before a Special Circumstance, or the trustee of the Trust after a Special Circumstance, for a distribution of that portion of his or her benefit that has become taxable. Upon the grant of such a petition, which grant shall not be unreasonably withheld (and, after a Special Circumstance, shall be granted), the Company or applicable Affiliate shall distribute to the Participant immediately available 20 funds in an amount equal to the taxable portion of his or her benefit. If the petition is granted, the tax liability distribution shall be made within 90 days of the date when the Participant's petition is granted. Such a distribution shall affect and reduce the benefits to be paid under this Plan. (b) If the Trust terminates in accordance with its terms and benefits are distributed from the Trust to a Participant in accordance therewith, the Participant's benefits under this Plan shall be reduced to the extent of such distributions. 11.6 Insurance. The Company and the Affiliates, on their own behalf or --------- on behalf of the trustee of the Trust, and, in their sole discretion, may apply for and procure insurance on the life of the Participant, in such amounts and in such forms as the Trust may choose. The Company, the Affiliates or the trustee of the Trust, as the case may be, shall be the sole owner and beneficiary of any such insurance. The Participant shall have no interest whatsoever in any such policy or policies, and at the request of the Company or an Affiliate shall submit to medical examinations and supply such information and execute such documents as may be required by the insurance company or companies to whom the Company or Affiliate have applied for insurance. 11.7 Legal Representation. The Company and each Affiliate is aware --------------------- that upon the occurrence of a Change in Control, the Board or the board of directors of a Participant's Employer (which might then be composed of new members) or a shareholder of the Company or the Participant's Employer, or of any successor corporation might then cause or attempt to cause the Company, an Affiliate or successor to refuse to comply with its obligations under the Plan and might cause or attempt to cause the Company or an Affiliate to institute, or may institute, litigation seeking to deny Participants the benefits intended under the Plan. In these circumstances, the purpose of the Plan could be frustrated. Accordingly, if, following a Change in Control, it should appear to any Participant that the Company, an Affiliate or any successor corporation has failed to comply with any of its obligations under the Plan or, if the Company, an Affiliate or any other person takes any action to declare the Plan void or unenforceable or institutes any litigation or other legal action designed to deny, diminish or to recover from any Participant the benefits intended to be provided, then the Company and the applicable Affiliate irrevocably authorize such Participant to retain counsel of his or her choice at the expense of the Company and an Affiliate (who shall be jointly and severally liable) to represent such Participant in connection with the initiation or defense of any litigation or other legal action, whether by or against the Company, an Affiliate or any director, officer, shareholder or other person affiliated with the Company, an Affiliate or any successor thereto in any jurisdiction. 21 ATTACHMENT 2.4-A Ohio Edison Company Deferred Compensation Plan for Directors. ------------------------------------------------------------- Merger of Plans. Effective as of December 31, 1997, the Ohio Edison --------------- Deferred Compensation Plan for Directors ("Ohio Edison Plan") was merged into this Plan. Definition of Director. The individuals who made deferral elections ---------------------- under the Ohio Edison Plan shall be considered "Directors" for purposes of this Plan even if they have not served on the Board or any board of directors of any Affiliate. Prior Elections to Defer. Any election to defer director's fees made ------------------------ under the Ohio Edison Plan prior to December 31, 1997 shall, to the extent such deferred fees and any earnings and losses credited to such deferred fees have not been paid to the Director or to his or her Beneficiary prior to such date, be treated as having been made under this Plan and shall be subject to all of the rights and limitations imposed on elections made under this Plan. Transfer of Account Balance. With respect to any Director who had a ---------------------------- balance in his or her account under the Ohio Edison Plan immediately prior to December 31, 1997, the balance of such account shall be transferred to a Transfer Account under this Plan as of December 31, 1997 and shall be administered in accordance with this Plan. Such Directors shall be permitted to designate how such transferred account balances shall be deemed invested as permitted under this Plan. Liability for Payment. All liabilities of the Ohio Edison Plan shall --------------------- be paid by the Company. Transfer of Liabilities and Payment of Accounts. If any account under ----------------------------------------------- the Ohio Edison Plan is in pay status or is otherwise payable to an Participant as of such date, it shall continue to be payable to that person under the same terms and conditions as were provided under the Ohio Edison Plan. The balance of any account under the Ohio Edison Plan shall become payable under the terms and conditions of this Plan; provided, however, that the Director's deferral elections, commencement date elections, and beneficiary elections made under the Ohio Edison Plan shall continue to be effective under this Plan unless amended or changed by the Director under the terms of this Plan. Crediting of Service. All service as a director of the Ohio Edison ---------------------- Company or any affiliate of Ohio Edison Company shall count as Years of Service under this Plan. 22 ATTACHMENT 2.4-B Centerior Energy Corporation Deferred Compensation Plan for Directors. --------------------------------------------------------------------- Merger of Plans. Effective as of January 1, 2000, the --------------- Centerior Energy Corporation Deferred Compensation Plan for Directors (the "Centerior Plan") was merged into this Plan. Definition of Director. The individuals who made deferral ---------------------- elections under the Centerior Plan shall be considered "Directors" for purposes of this Plan even if they have not served on the Board or any board of directors of any Affiliate. Prior Elections to Defer. Any election to defer director's ------------------------ fees made under the Centerior Plan prior to January 1, 2000 shall, to the extent such deferred fees and any earnings and losses credited to such deferred fees have not been paid to the Director or to his or her Beneficiary prior to such date, be treated as having been made under this Plan and shall be subject to all of the rights and limitations imposed on elections made under this Plan. Transfer of Account Balance. With respect to any Director who --------------------------- had a balance in his or her account under the Centerior Plan immediately prior to January 1, 2000, the balance of such account shall be transferred to a Transfer Account under this Plan as of January 1, 2000 and shall be administered in accordance with this Plan. Such Directors shall be permitted to designate how such transferred account balances shall be deemed invested as permitted under this Plan. Liability for Payment. All liabilities of the Centerior Plan shall be --------------------- paid by the Company. Transfer of Liabilities and Payment of Accounts. If any ----------------------------------------------- account under the Centerior Plan is in pay status or is otherwise payable to an Participant as of such date, it shall continue to be payable to that person under the same terms and conditions as were provided under the Centerior Plan. The balance of any account under the Centerior Plan shall become payable under the terms and conditions of this Plan; provided, however, that the Director's deferral elections, commencement date elections, and beneficiary elections made under the Centerior Plan shall continue to be effective under this Plan unless amended or changed by the Director under the terms of this Plan. Crediting of Service. All service as a director of Centerior -------------------- Energy Corporation or any affiliate of Centerior Energy Corporation shall count as Years of Service under this Plan. 23 ATTACHMENT 2.4-C Deferred Remuneration Plan for Outside Directors of GPU, Inc. ------------------------------------------------------------- And Deferred Stock Unit Plan for Outside Directors of GPU, Inc. ----------------------------------------------------------- And Deferred Remuneration Plan for Outside Directors of Jersey Central Power & Light - -------------------------------------------------------------------------------- Transfers from GPU Plans. Any individual who participated in ------------------------ the Deferred Remuneration Plan for Outside Directors of GPU, Inc., Deferred Stock Unit Plan for Outside Directors of GPU, Inc., or the Deferred Remuneration Plan for Outside Directors of Jersey Central Power & Light (collectively the "GPU Plans") and who was selected as a member of the board of directors for the Company or Jersey Central Power & Light after November 7, 2001, may elect to transfer his or her account under each GPU Plan to this Plan. Prior Elections. Any election to defer director's fees made --------------- under any GPU Plan prior to November 7, 2001 shall, to the extent such deferred fees and any earnings credited to such deferred fees have not been paid to the director or to his or her beneficiary prior to such date, be treated as having been made under this Plan and shall be subject to all of the rights and limitations imposed on elections made under this Plan. Transfer of Account Balance. Any Director who had a balance in --------------------------- his or her account under a GPU Plan immediately prior to November 7, 2001 may elect to transfer such account's balance to a Transfer Account under this Plan as of November 7, 2001. The Committee shall establish subaccounts within the Transfer Account to reflect and administer Pre-Retirement and Retirement Accounts transferred from the GPU Plans. From the date of the election, the Transfer Account shall be deemed to be invested in the Moody's Investment Fund. The Moody's Investment Fund is an Investment Fund established by the Committee pursuant to Section 3.4 of the Plan and, the balance transferred from a GPU Plan shall be adjusted in the same manner as the balances of Accounts of all other Participants that are deemed to be invested in the Moody's Investment Fund. In the event the Committee modifies the interest rate or the measurement period, amends any feature of the Moody's Investment Fund, or eliminates the Moody's Investment Fund, such modification, amendment or elimination shall apply to all Participants including any Director that transfers his or her account balance from a GPU Plan to this Plan. After January 1, 2002, a Director that transfers his or her account balance from a GPU Plan may direct the Investment Funds in which his or her Transfer Account is deemed invested as permitted by Section 3.5(c). Liability for Payment. Liabilities of the GPU Plans --------------------- transferred to the Company shall be paid by the Company. Any liability of the GPU Plans transferred to an Affiliate shall be paid by the Affiliate. 24 Payment of Accounts. An account balance of a GPU Plan shall be ------------------- transferred to this Plan as of the later of the date of the Director's election or November 7, 2001. If any account under a GPU Plan is in pay status or is otherwise payable to an Participant as of such date, it shall continue to be payable to that person under the same terms and conditions as were provided under the applicable GPU Plan. The balance of any account under a GPU Plan shall become payable under the terms and conditions of this Plan; provided, however, that the Director's deferral elections, commencement date elections, and beneficiary elections made under the GPU Plan shall continue to be effective under this Plan unless amended or changed under the terms of this Plan. Crediting of Service and Years of Deferral. All service as a director ------------------------------------------ with GPU, Inc. or any affiliate of GPU, Inc. shall count as Years of Service under this Plan. A full year during which a Director deferred fees under a GPU Plan shall count as a full year of deferral under this Plan for purposes of withdrawals under Section 4.4. 25 Scope of Change --------------- Rev. 0 - Approved by FE Board on 11/19/02. Incorporates provisional changes resulting from changing the trustee to State Street. 26 P EX-10 7 fe_ex10-32.txt EX. 10-32 EXEC. & INCENTIVE COMP PLAN 2002 FirstEnergy Executive Incentive Compensation Plan 2002 The Executive Incentive Compensation Plan (EICP) is designed to attract, retain and reward executives; to more closely align the interests of executives and shareholders; and to promote growth in shareholder value. The Plan consists of a Short-Term Incentive Program (STIP) for 2002; a Long-Term Incentive Program (LTIP) for the period 2002 - 2004, and a Stock Option Program. Target opportunities for each program are shown in Attachment 1. Short-Term Incentive Program (STIP) ----------------------------------- Eligibility - ----------- Employees with a March 1, 2002 market rate at or above $98,800 who have an approved reporting relationship are eligible to participate in the STIP. Employees who are employed as of January 1, 2002, must work through March 31, 2002, to be eligible for an STIP award. Newly hired employees must be on the payroll prior to October 1, 2002, to be eligible for an STIP award. Eligible employees who have separated employment during the year due to retirement, disability, death, or under conditions for which the employee qualifies and elects benefits under the FirstEnergy Severance Benefits Plan will receive a prorated award based on the number of months worked in an eligible position. Eligible employees who voluntarily resign or are involuntarily separated for cause at any time during the plan year or between December 31, 2002, and the date awards are paid, are ineligible to receive an STIP award. A performance rating of Does Not Meet Expectations also disqualifies an employee from receiving an STIP award. Eligible employees who work in an EICP position for less than the full plan year will receive a prorated award based on the number of months worked in an eligible position. Transfer between Plans - ---------------------- STIP awards are based on whole months of eligibility in an incentive plan. Thus, employees who transfer from one incentive plan to another and work the full year, or those who exit under qualifying circumstances described above will have their incentive awards prorated in whole month increments. Monthly increments are determined by the effective date of the employee's move. 1 For a move resulting in a change in incentive plan eligibility that is effective between the 1st and 15th of any month except December, the employee becomes eligible for the plan into which they are moving for that entire month. If the move is effective on or after the 16th of any month except January, the employee becomes eligible for the plan into which they are moving on the 1st of the following month. Employees hired or changing plans at any time during January will be credited with plan eligibility in the "new" plan for the entire month of January. Employees who change plans at any time on or after November 16 will continue their eligibility in the "old" plan for the entire month of December, and will become eligible for the "new" plan in January. If an employee experiences a change in market rate within the EICP group during the plan year, the employee will receive a prorated STIP award based on the number of months at each market rate. Key Performance Indicators (KPIs) - --------------------------------- Performance goals consist of FirstEnergy Financial KPIs and Operational KPIs. FirstEnergy Financial KPIs apply to all employees. Operational KPIs are established by each Business Unit Vice President. The weighting of Financial KPIs and Operational KPIs varies among eligible employees depending upon their job level. Incentive Opportunity - --------------------- Each KPI has a threshold, target and maximum level of achievement. The achievement of Financial KPIs at or above threshold will generate a payout from 50% to 200% of the target award. The achievement of Operational KPIs at or above threshold will generate a payout from 50% to 150% of target. Results achieved between threshold and target, and target and maximum, will be interpolated. STIP awards for the 2002 plan year will be paid in March 2003. Awards are subject to tax withholding and are eligible for Employee Savings Plan contributions. STIP awards will not be paid unless total earnings exceed the amount of dividends paid plus the maximum awards from all incentive plans. Plan participants may elect to defer a portion or all of their STIP award under the terms of the Executive Deferred Compensation Plan (EDCP). Discretionary Award - ------------------- There may be instances where an employee has demonstrated extraordinary responsiveness or has made a substantial contribution that will not be properly recognized in the STIP award process. In these cases, the Company (and/or the Compensation Committee of the Board of Directors) may, at its discretion, grant a special discretionary award to the employee. 2 Long-Term Incentive Program (LTIP) ---------------------------------- Eligibility - ----------- An employee who is hired or promoted into the EICP eligible group during January 2002 will be eligible to participate in the 2002 LTIP. An employee hired or promoted into the EICP group on or after February 1, 2002, will become eligible for the LTIP in 2003, assuming he/she remains in an eligible position. An employee must work a minimum of 12 months in an EICP eligible position during the three-year (36-month) plan cycle to be eligible for an award. Thus, an executive who separates for any reason during 2002 will not be eligible to receive an LTIP award from the 2002 program. An eligible employee must be actively employed as of December 31, 2004, or have separated due to retirement, disability or death; or under conditions for which the employee qualifies and elects benefits under the FirstEnergy Severance Benefits Plan. In such cases, the employee will receive a prorated award at the time of separation, based on the number of months of participation and the Company's TSR rating at the time. An employee who voluntarily resigns or is separated for cause at any time during the three-year plan cycle, or between December 31, 2004, and the award payment date, is ineligible to receive an LTIP award from the 2002 program. If an EICP eligible employee is no longer in an eligible position on December 31, 2004, his/her LTIP award will be prorated to reflect the number of months worked in an eligible position during the three-year plan cycle. Performance Shares - ------------------ On January 1, 2002, each eligible employee's LTIP award is converted into "Performance Shares" of FirstEnergy common stock based on the average of the high and low common stock prices on the last trading day in 2001. These shares are placed into a Performance Share Account for three years (2002 - 2004). During the 2002 - 2004 plan cycle, dividend equivalents will be converted into additional shares based on the closing stock price on the date the dividends are paid. At the end of the three-year plan cycle, the employee's account value will be based on the average of the high and low prices on the last trading day in December 2004. The account value may be adjusted upward or downward based upon the total shareholder return (TSR) ranking of FirstEnergy common stock relative to an energy services company index during the three-year period. The purpose of applying a TSR factor is to strengthen the linkage between the participant's total compensation and the long-term growth of shareholder value. 3 If the Company's TSR ranking is at the 63rd percentile, the award payout will be 100% of the account value. If the TSR rating is at or above the 86th percentile, the award payout will be 150% of the account value. If the TSR is at the 41st percentile, the award payout will be 50% of the account value. Award payouts for a ranking above the 41st and below the 86th percentile will be interpolated. For a TSR ranking below the 41st percentile, no award payment will be made. Attachment 2 provides a LTIP award example. Award Payments - -------------- Awards for the 2002 - 2004 cycle will be paid in March 2005. Plan participants may elect to defer a portion or all of their LTIP award under the provisions of the Executive Deferred Compensation Plan (EDCP). Stock Option Program -------------------- In 2002, eligible employees will receive stock option grants that will allow them to purchase a specified number of common stock shares at a fixed grant price over a defined period of time. The number of stock options granted and a stock option agreement will be communicated to recipients at the time of the grant. Terms ----- For the purposes of this Plan, the term FirstEnergy is defined as FirstEnergy Corp. and all of its operating companies to which this Plan has been extended. The term "Company" refers to FirstEnergy Corp. or its operating companies individually, as appropriate. Each employee's rights under the Plan are at all times governed by the official text of the Executive and Directors Incentive Compensation Plan Document and are in no way altered or modified by the contents of this summary. Beneficiary - ----------- Each executive may, at any time, designate one or more persons as the executive's primary or contingent beneficiary (ies) to whom awards earned under this Plan shall be paid in the event of the executive's death prior to payment of such awards to the executive. In the absence of an effective beneficiary designation, or if all beneficiaries predecease the executive, the executive's designated beneficiary shall be the person in the first of the following classes in which there is a survivor: the executive's surviving spouse; the executive's estate. 4 Right to Modify or Terminate - ---------------------------- This Plan may be amended or terminated at any time with or without notice by the Compensation Committee of the Board of Directors of FirstEnergy. If it is determined that significant unusual events occurred that impacted the FirstEnergy's reported earnings but do not truly reflect the achieved operating results of the FirstEnergy, then the Compensation Committee may, in its sole discretion, increase or decrease the amount of any awards determined by this Plan or even determine that no awards will be paid. Not withstanding, the Committee shall have no authority to adjust upwards the amount payable to a Covered Employee with respect to a particular Award, to take any of the foregoing actions or to take any other action to the extent that such action or the Committee's ability to take such action would cause any Award under the Plan to any Covered Employee to fail to qualify as "performance-based compensation" within the meaning of Code Section 162(m)(4) and the regulations issued thereunder. No Employment Contract or Funded Trust - -------------------------------------- Nothing in this Plan shall be construed as giving any participant the right to be retained in the employ of any Company, nor shall any Company be required, by virtue of the existence of this Plan, to maintain the employment of any participant through any specified date. All awards paid under this Plan shall at all times constitute general unsecured liabilities of any Company, payable out of its own general assets. In no event shall any Company be obliged to reserve any funds or assets to secure the payment of such amounts and nothing contained in the Plan shall confer upon any participant the right, title or interest of any assets of any Company. Administration - -------------- The Plan is administered by the Human Resources Department. 5
Attachment 1 Total Compensation Opportunity 2002 ================= ============================== ========================================================= ===================== SHORT-TERM (STIP) LONG-TERM (LTIP) TOTAL ------------------------------ --------------------------------------------------------- --------------------- Total Incentive Executive Annual Incentive Performance Share Stock Option Compensation Tier Target Opportunity* Target Opportunity* Target Opportunity* Opportunity* ================= ============================== =========================== ============================= ===================== V 25% 5% 35% 65% ================= ============================== =========================== ============================= ===================== *Opportunity as a percent of the employee's March 1, 2002 market rate
======================================================================== STIP AWARD LEVERAGE (TIER V) - ------------------------------------------------------------------------ KPIs WEIGHT THR TGT MAX - ------------- -------------- ------------- ------------ ---------------- Financial 20% 50% 100% 200% - ------------- -------------- ------------- ------------ ---------------- Operational 80% 50% 100% 150% ============= ============== ============= ============ ================ Total 100% 50% 100% 160% ============= ============== ============= ============ ================ 6 Attachment 2 FirstEnergy 2002 Executive Incentive Compensation Plan Long-Term Incentive Program (LTIP) Performance Share Example Name: Jane Executive Market Rate: $100,000 Target Incentive: 5% of Market Rate Target Opportunity: $5,000 Performance Share Award: 142.207 shares (35.155/share) Performance shares mature at the end of 2004 and are payable in March 2005 based on the following factors: o The account value after dividend equivalents are credited to the executive's account during the performance period o The common stock price calculated by averaging the high and low market price of the Company's common stock on the last trading date of 2004 o The total shareholder return (TSR) of the Company's common stock during the performance period relative to the peer company index. The TSR ranking will determine a performance factor which will either increase or decrease the value of the performance share account The following table illustrates awards at various TSR percentile rankings assuming that no dividends are paid and that the stock price does not appreciate during the three-year performance period. ============================== ====================== ======================= Performance TSR Ranking Award Payout* Factor ============================== ====================== ======================= 86 - 100th Percentile $7,500 150% - ------------------------------ ---------------------- ----------------------- 75th Percentile* $6,250 125% - ------------------------------ ---------------------- ----------------------- 63rd Percentile* $5,000 100% - ------------------------------ ---------------------- ----------------------- 52nd Percentile* $3,750 75% - ------------------------------ ---------------------- ----------------------- 41st Percentile $2,500 50% - ------------------------------ ---------------------- ----------------------- 1 - 40th Percentile $0 0% - ------------------------------ ---------------------- ----------------------- * Award payouts interpolated between the 86th and 41st percentile. ========================================================================== 7 EX-12 8 fe_ex12-1.txt EX. 12-1 FIXED CHARGE RATIO - FE EXHIBIT 12.1 FIRSTENERGY CORP. CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
Year Ended December 31, ------------------------------------------------------------- 1998 1999 2000 2001 2002 ----------- ----------- ----------- ----------- -------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items and cumulative effect of accounting changes........................................... $ 441,396 $ 568,299 $ 598,970 $ 654,946 $ 686,401 Interest and other charges, before reduction for amounts capitalized.......................................... 608,618 585,648 556,194 591,192 970,780 Provision for income taxes..................................... 321,699 394,827 376,802 474,457 549,476 Interest element of rentals charged to income (a).............. 283,869 279,519 271,471 258,561 246,416 ---------- ---------- ---------- ---------- ---------- Earnings as defined.......................................... $1,655,582 $1,828,293 $1,803,437 $1,979,156 $2,453,073 ========== ========== ========== ========== ========== FIXED CHARGES AS DEFINED IN REGULATION S-K: Interest expense............................................... $ 542,819 $ 509,169 $ 493,473 $ 519,131 $ 891,833 Subsidiaries' preferred stock dividend requirements............ 65,299 76,479 62,721 72,061 78,947 Adjustments to subsidiaries' preferred stock dividends to state on a pre-income tax basis........................... 43,370 44,829 32,098 43,931 54,059 Interest element of rentals charged to income (a).............. 283,869 279,519 271,471 258,561 246,416 ---------- ---------- ---------- ---------- ---------- Fixed charges as defined..................................... $ 935,357 $ 909,996 $ 859,763 $ 893,684 $1,271,255 ========== ========== ========== ========== ========== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES (b).................................................... 1.77 2.01 2.10 2.21 1.93 ==== ==== ==== ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined. (b) These ratios exclude fixed charges applicable to the guarantee of the debt of a coal supplier aggregating $3,828,000 for the year ended December 31, 1998. The guarantee and related coal supply contract debt expired December 31, 1999.
EX-13 9 fe_ex13.txt EX. 13 ANNUAL REPORT - FE Management Report The consolidated financial statements were prepared by the management of FirstEnergy Corp., who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, independent public accountants, have expressed an unqualified opinion on the Company's 2002 consolidated financial statements. The Company's internal auditors, who are responsible to the Audit Committee of the Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls. The Audit Committee consists of six nonemployee directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent public accountants and the internal auditors; appointment of independent accountants to conduct the normal annual audit and special purpose audits as may be required; reviewing and approving all services, including any non-audit services, performed for the Company by the independent public accountants and reviewing the related fees; and reporting to the Board of Directors the Committee's findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee reviews the independent accountants' internal quality control procedures and reviews all relationships between the independent accountants and the Company, in order to assess the auditors' independence. The Committee also reviews management's programs to monitor compliance with the Company's policies on business ethics and risk management. The Audit Committee held nine meetings in 2002. Richard H. Marsh Senior Vice President and Chief Financial Officer Harvey L. Wagner Vice President, Controller and Chief Accounting Officer Report of Independent Public Accountants To the Stockholders and Board of Directors of FirstEnergy Corp.: In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, common stockholders' equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of FirstEnergy Corp. and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The consolidated financial statements of FirstEnergy Corp. and subsidiaries as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statements, before the revisions described in Notes 2 and 8 to the 2002 consolidated financial statements, in their report dated March 18, 2002. As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for goodwill in 2002. As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for its investments in Avon Energy Partners Holdings and Emdersa in 2002. As discussed above, the consolidated financial statements of FirstEnergy Corp. and subsidiaries as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent accountants who have ceased operations. As described in Note 2 to the consolidated financial statements, revisions have been made to include the transitional disclosures required by Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, which was adopted by the Company as of January 1, 2002. In our opinion the transitional disclosures for 2001 and 2000 are appropriate. However, we were not engaged to audit, review, or apply any procedures to the 2001 and 2000 consolidated financial statements of the Company other than with respect to such disclosures and, accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 consolidated financial statements taken as a whole. Additionally, as described in Note 8 to the consolidated financial statements, the Company changed the composition of its reportable segments in 2002. Accordingly, the corresponding 2001 and 2000 reportable segments disclosures have been revised to conform to the 2002 presentation. We audited the revisions that were applied to the 2001 and 2000 reportable segments disclosures reflected in Note 8 to the 2002 consolidated financial statements. In our opinion, such revisions are appropriate and have been properly applied. PricewaterhouseCoopers LLP Cleveland, OH, February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. Report of Previous Independent Public Accountants To the Stockholders and Board of Directors of FirstEnergy Corp.: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of FirstEnergy Corp. (an Ohio corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholders' equity, preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of FirstEnergy Corp. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities by adopting Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002
FIRSTENERGY CORP. SELECTED FINANCIAL DATA For the Years Ended December 31, 2002 2001 2000 1999 1998 - -------------------------------------------------------------------------------------------------------------------------- (In thousands, except per share amounts) Revenues....................................... $12,151,997 $ 7,999,362 $ 7,028,961 $ 6,319,647 $ 5,874,906 ----------------------------------------------------------------------- Income Before Extraordinary Item and Cumulative Effect of Accounting Changes..... $ 686,401 $ 654,946 $ 598,970 $ 568,299 $ 441,396 ----------------------------------------------------------------------- Net Income..................................... $ 629,280 $ 646,447 $ 598,970 $ 568,299 $ 410,874 ----------------------------------------------------------------------- Basic Earnings per Share of Common Stock: Before Extraordinary Item and Cumulative Effect of Accounting Changes.............. $2.34 $2.85 $2.69 $2.50 $1.95 After Extraordinary Item and Cumulative Effect of Accounting Changes.............. $2.15 $2.82 $2.69 $2.50 $1.82 ----------------------------------------------------------------------- Diluted Earnings per Share of Common Stock: Before Extraordinary Item and Cumulative Effect of Accounting Changes.............. $2.33 $2.84 $2.69 $2.50 $1.95 After Extraordinary Item and Cumulative Effect of Accounting Changes.............. $2.14 $2.81 $2.69 $2.50 $1.82 ----------------------------------------------------------------------- Dividends Declared per Share of Common Stock... $1.50 $1.50 $1.50 $1.50 $1.50 ----------------------------------------------------------------------- Total Assets................................... $33,580,773 $37,351,513 $17,941,294 $18,224,047 $18,192,177 ----------------------------------------------------------------------- Capitalization at December 31: Common Stockholders' Equity................. $ 7,120,049 $ 7,398,599 $ 4,653,126 $ 4,563,890 $ 4,449,158 Preferred Stock: Not Subject to Mandatory Redemption....... 335,123 480,194 648,395 648,395 660,195 Subject to Mandatory Redemption........... 428,388 594,856 161,105 256,246 294,710 Long-Term Debt*............................. 10,872,216 12,865,352 5,742,048 6,001,264 6,352,359 ----------------------------------------------------------------------- Total Capitalization*..................... $18,755,776 $21,339,001 $11,204,674 $11,469,795 $11,756,422 ======================================================================= * 2001 includes approximately $1.4 billion of long-term debt (excluding long-term debt due to be repaid within one year) included in "Liabilities Related to Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2001.
PRICE RANGE OF COMMON STOCK The Common Stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol "FE" and is traded on other registered exchanges. 2002 2001 - ------------------------------------------------------------------------------- First Quarter High-Low........... $39.12 $30.30 $31.75 $25.10 Second Quarter High-Low.......... 35.12 31.61 32.20 26.80 Third Quarter High-Low........... 34.78 24.85 36.28 29.60 Fourth Quarter High-Low.......... 33.85 25.60 36.98 32.85 Yearly High-Low.................. 39.12 24.85 36.98 25.10 - ------------------------------------------------------------------------------- Prices are based on reports published in The Wall Street Journal for New York ----------------------- Stock Exchange Composite Transactions. HOLDERS OF COMMON STOCK There were 163,423 and 162,762 holders of 297,636,276 shares of FirstEnergy's Common Stock as of December 31, 2002 and January 31, 2003, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 5A. FIRSTENERGY CORP. Management's Discussion and Analysis of Results of Operations and Financial Condition This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), the availability and cost of capital, our ability to accomplish or realize anticipated benefits from strategic initiatives and other similar factors. FirstEnergy Corp. is a registered public utility holding company that provides regulated and competitive energy services (see Results of Operations - Business Segments) domestically and internationally. The international operations were acquired as part of FirstEnergy's acquisition of GPU, Inc. in November 2001. GPU Capital, Inc. and its subsidiaries provide electric distribution services in foreign countries. GPU Power, Inc. and its subsidiaries develop, own and operate generation facilities in foreign countries. Sales are planned but not pending for all of the international operations (see Capital Resources and Liquidity). Prior to the GPU merger, regulated electric distribution services were provided to portions of Ohio and Pennsylvania by our wholly owned subsidiaries - Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power Company (Penn) and The Toledo Edison Company (TE) with American Transmission Systems, Inc. (ATSI) providing transmission services. Following the GPU merger, regulated services are also provided through wholly owned subsidiaries - Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec) - providing electric distribution and transmission services to portions of Pennsylvania and New Jersey. The coordinated delivery of energy and energy-related products, including electricity, natural gas and energy management services, to customers in competitive markets is provided through a number of subsidiaries, often under master contracts providing for the delivery of multiple energy and energy-related services. Prior to the GPU merger, competitive services were principally provided by FirstEnergy Solutions Corp. (FES), FirstEnergy Facilities Services Group, LLC (FSG) and MARBEL Energy Corporation. Following the GPU merger, competitive services are also provided through MYR Group, Inc. GPU Merger On November 7, 2001, the merger of FirstEnergy and GPU became effective with FirstEnergy being the surviving company. The merger was accounted for using purchase accounting under the guidelines of Statement of Financial Accounting Standards No. (SFAS) 141, "Business Combinations." Under purchase accounting, the results of operations for the combined entity are reported from the point of consummation forward. As a result, our financial statements for 2001 reflect twelve months of operations for our pre-merger organization and seven weeks of operations (November 7, 2001 to December 31, 2001) for the former GPU companies. In 2002, our financial statements include twelve months of operations for both our pre-merger organization and the former GPU companies. Additional goodwill resulting from the merger ($2.3 billion) plus goodwill existing at GPU ($1.9 billion) at the time of the merger is not being amortized, reflecting the application of SFAS 142, "Goodwill and Other Intangible Assets." Goodwill continues to be subject to review for potential impairment (see Significant Accounting Policies - Goodwill). As a result of the merger, we issued nearly 73.7 million shares of our common stock, which are reflected in the calculation of earnings per share of common stock in 2002 and for the seven-week period outstanding in 2001. Results of Operations Net income decreased to $629.3 million in 2002, compared to $646.4 million in 2001 and $599.0 million in 2000. Net income in 2002 included the net after-tax charge of $57.1 million resulting from the cumulative effect of changes in accounting resulting from divestiture activities discussed below. Net income in 2001 included the cumulative effect of an accounting change resulting in a net after-tax charge of $8.5 million (see Cumulative Effect of Accounting Changes). Excluding the former GPU companies' results (and related interest expense on acquisition debt), net income decreased to $469.4 million in 2002 from $615.5 million in 2001 due in large part to the incremental costs related to the extended Davis-Besse outage and a number of one-time charges summarized in the table below. In addition, SFAS 142, implemented January 1, 2002, resulted in the cessation of goodwill amortization. In 2001, amortization of goodwill reduced net income by approximately $57 million ($0.25 per share of common stock). Excluding the former GPU companies' results (and related interest expense on acquisition debt), net income increased in 2001 due to reduced depreciation and amortization, general taxes and net interest charges. The benefits of these reductions were offset in part by lower retail electric sales, increased other operating expenses and higher gas costs. Incremental costs related to the extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration) reduced basic and diluted earnings per share of common stock by $0.47 in 2002. In addition, the table below displays one-time charges that resulted in a comparative net reduction to basic and diluted earnings of $0.46 per share of common stock in 2002, compared to 2001. The impact of domestic and world economic conditions on the electric power industry limited our divestiture program during 2002. By the end of 2001, we had successfully completed the sale of our Australian gas transmission companies, had reached agreement with Aquila, Inc. for the sale of our holdings of electric distribution facilities in the United Kingdom (UK) and executed an agreement with NRG Energy Inc. (NRG) for the sale of four coal-fired power plants. However, the UK transaction with Aquila 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 Energy Partners Holdings (Avon) for approximately $1.9 billion (including the assumption of $1.7 billion of debt). In the fourth quarter of 2002, we recognized a $50 million impairment of our Avon investment. On August 8, 2002, we notified NRG that we were canceling our agreement with them for their purchase of the four fossil plants because NRG had stated that it could not complete the transaction under the original terms of the agreement. We were also actively pursuing the sale of an electric distribution company in Argentina - GPU Empressa Distribuidora Electrica Regional S.A. and its affiliates (Emdersa). With the deteriorating economic conditions in Argentina no sale could be completed by December 31, 2002. Further information on the impact of the changes in accounting related to our divestiture activities is available in the "Cumulative Effect of Accounting Changes" section and in the discussion of depreciation charges in the "Expenses" section below. One-time pre-tax charges to earnings before the cumulative effect of accounting changes are summarized in the following table: One-time Charges ---------------- 2002 2001 Change ------------------------------------------------------------------------------- (In millions) Investment impairments $100.7 -- $100.7 Pennsylvania deferred energy costs 55.8 -- 55.8 Lake Plants - depreciation and sale costs 29.2 -- 29.2 Long-term derivative contract adjustment 18.1 -- 18.1 Generation project cancellation 17.1 -- 17.1 Severance costs - 2002 11.3 -- 11.3 Uncollectible reserve and contract losses -- 9.2 (9.2) Early retirement costs - 2001 -- 8.8 (8.8) Estimated claim settlement 16.8 -- 16.8 ----------------------------------------------------------------------------- $249.0 $18.0 $231.0 ============================================================================= Reduction to earnings per share of common stock Basic $0.51 $0.05 $0.46 ============================================================================= Diluted $0.51 $0.05 $0.46 ============================================================================= Previously reported variances of revenues, expenses, income taxes and net income between 2001 as compared to 2000 included in Results of Operations - Business Segments have been reclassified as a result of segment information reclassifications (see Note 8 for additional discussion). In addition, previously reported comparisons of sales of electricity between 2001 as compared to 2000 have also been reclassified as a result of adoption of Emerging Issues Task Force (EITF) Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" (see Implementation of Recent Accounting Standard for additional disclosure). Revenues Total revenues increased $4.2 billion in 2002, which included more than $4.5 billion incremental revenues for the former GPU companies in 2002 (twelve months), compared to 2001 (seven weeks). Excluding results from the former GPU companies, total revenues increased $24.7 million following a $336.7 million increase in 2001. The additional sales in both years resulted from an expansion of our unregulated businesses, which more than offset lower sales from our electric utility operating companies (EUOC). Sources of changes in pre-merger and post-merger companies' revenues during 2002 and 2001, compared to the prior year, are summarized in the following table: Sources of Revenue Changes 2002 2001 --------------------------------------------------------------------- Increase (Decrease) (In millions) Pre-Merger Companies: Electric Utilities (Regulated Services): Retail electric sales $ (328.5) $(240.5) Other revenues 18.4 (22.6) --------------------------------------------------------------------- Total Electric Utilities (310.1) (263.1) --------------------------------------------------------------------- Unregulated Businesses (Competitive Services): Retail electric sales 136.4 (19.9) Wholesale electric sales: Nonaffiliated 140.0 254.4 Affiliated 345.3 32.7 Gas sales (171.7) 226.1 Other revenues (115.2) 106.5 --------------------------------------------------------------------- Total Unregulated Businesses 334.8 599.8 --------------------------------------------------------------------- Total Pre-Merger Companies 24.7 336.7 --------------------------------------------------------------------- Former GPU Companies: Electric utilities 3,782.4 570.4 Unregulated businesses 687.4 101.9 --------------------------------------------------------------------- Total Former GPU Companies 4,469.8 672.3 Intercompany Revenues (341.9) (38.6) --------------------------------------------------------------------- Net Revenue Increase $4,152.6 $ 970.4 ===================================================================== Electric Sales Shopping by Ohio customers for alternative energy suppliers combined with the effect of a sluggish national economy on regional business reduced retail electric sales revenues of our pre-merger EUOCs by $328.5 million (or 7.1%) in 2002 compared to 2001. Since Ohio opened its retail electric market to competing generation suppliers in 2001, sales of electric generation by alternative suppliers in our franchise areas have risen steadily, providing 23.6% of total energy delivered to retail customers in 2002, compared to 11.3% in 2001. As a result, generation kilowatt-hour sales to retail customers by the EUOC were 14.2% lower in 2002 than the prior year, which reduced regulated retail electric sales revenues by $230.6 million. Revenue from distribution deliveries decreased by $11.7 million in 2002 compared to 2001. KWH deliveries to franchise customers were 0.5% lower in 2002 compared to the prior year. The decrease resulted from the net effect of a 6.3% increase in kilowatt-hour deliveries to residential customers (due in large part to warmer summer weather in 2002) offset by a 3.2% decline in kilowatt-hour deliveries to commercial and industrial customers as a result of sluggish economic conditions. The remaining decrease in regulated retail electric sales revenues resulted from additional transition plan incentives provided to customers to promote customer shopping for alternative suppliers - $86.0 million of additional credits in 2002 compared to 2001. These reductions to revenue are deferred for future recovery under our Ohio transition plan and do not materially affect current period earnings. Despite the decrease in kilowatt-hour sales by our pre-merger EUOC, total electric generation sales increased by 22.0% in 2002 compared to the prior year as a result of higher kilowatt-hour sales by our competitive services segment. Revenues from the wholesale market increased $501.4 million in 2002 from 2001 and kilowatt-hour sales more than doubled. More than half of the increase resulted from additional affiliated company sales by FES to Met-Ed and Penelec. FES assumed the supply obligation in the third quarter of 2002 for a portion of Met-Ed's and Penelec's provider of last resort (PLR) supply requirements (see State Regulatory Matters - Pennsylvania). The increase also included sales into the New Jersey market as an alternative supplier for a portion of New Jersey's basic generation service (BGS). Retail sales by our competitive services segment increased by $136.4 million as a result of a 59.0% increase in kilowatt-hour sales in 2002 from 2001. That increase resulted from retail customers switching to FES, our unregulated subsidiary, under Ohio's electricity choice program. The higher kilowatt-hour sales in Ohio were partially offset by lower retail sales in markets outside of Ohio. In 2001, our pre-merger EUOC retail revenues decreased by $240.5 million compared to 2000, principally due to lower generation sales volume resulting from the first year of customer choice in Ohio. Sales by alternative suppliers increased to 11.3% of total energy delivered compared to 0.8% in 2000. Implementation of a 5% reduction in generation charges for residential customers as part of Ohio's electric utility restructuring in 2001 also contributed $51.2 million to the reduced electric sales revenues. Kilowatt-hour deliveries to franchise customers were down a more moderate 1.7% due in part to the decline in economic conditions, which was a major factor resulting in a 3.1% decrease in kilowatt-hour deliveries to commercial and industrial customers. Other regulated electric revenues decreased by $22.6 million in 2001, compared to the prior year, due in part to reduced customer reservation of transmission capacity. Total electric generation sales increased by 2.7% in 2001 compared to the prior year with sales to the wholesale market being the largest single factor contributing to this increase. Kilowatt-hour sales to wholesale customers more than doubled from 2000 and revenues increased $287.1 million in 2001 from the prior year. The higher kilowatt-hour sales benefited from increased availability of power to sell into the wholesale market, due to additional internal generation and increased shopping by retail customers from alternative suppliers, which allowed us to take advantage of wholesale market opportunities. Retail kilowatt-hour sales by our competitive services segment increased by 3.6% in 2001, compared to 2000, primarily due to expanding sales within Ohio as a result of retail customers switching to FES under Ohio's electricity choice program. The higher kilowatt-hour sales in Ohio were partially offset by lower sales in markets outside of Ohio as some customers returned to their local distribution companies. Despite an increase in kilowatt-hour sales in Ohio's competitive market, declining sales to higher-priced eastern markets contributed to an overall decline in retail competitive sales revenue in 2001 from the prior year. Changes in electric generation sales and distribution deliveries in 2002 and 2001 for our pre-merger companies are summarized in the following table: Changes in KWH Sales 2002 2001 ------------------------------------------------------------------ Increase (Decrease) Electric Generation Sales: Retail - Regulated services (14.2)% (12.2)% Competitive services 59.0% 3.6% Wholesale 122.6% 117.2% ------------------------------------------------------------------ Total Electric Generation Sales 22.0% 2.7% ================================================================== EUOC Distribution Deliveries: Residential 6.3% 1.7% Commercial and industrial (3.2)% (3.1)% ------------------------------------------------------------------ Total Distribution Deliveries (0.5)% (1.7)% ================================================================== Our regulated and unregulated subsidiaries record purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with Emerging Issues Task Force (EITF) Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." This gross basis classification of revenues and costs may not be comparable to other energy companies that operate in regions that have not established ISOs and do not meet EITF 99-19 criteria. The aggregate purchase and sales transactions for the three years ended December 31, 2002, are summarized as follows: 2002 2001 2000 -------------------------------------------------------------- (In millions) Sales $453 $142 $315 Purchases 687 204 271 -------------------------------------------------------------- FirstEnergy's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from the PJM ISO from power sales (as reflected in the table above) during periods when we had additional available power capacity. Revenues also include sales by FirstEnergy of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when we required additional power to meet our retail load requirements and, secondarily, to sell in the wholesale market. Nonelectric Sales Nonelectric sales revenues declined by $284.6 million in 2002 from 2001. The elimination of coal trading activities in the second half of 2001 and reduced natural gas sales were the primary factors contributing to the lower revenues. Reduced gas revenues resulted principally from lower prices compared to 2001. Despite a slight reduction in sales volume and lower prices in 2002, margins from gas sales improved (see Expenses below). Reduced revenues from the facilities services group also contributed to the decrease in other sales revenue in 2002, compared to 2001. In 2001, nonelectric revenues increased $332.6 million, with natural gas revenues providing the largest source of increase. Beginning November 1, 2000, residential and small business customers in the service area of a nonaffiliated gas utility began shopping among alternative gas suppliers as part of a customer choice program. FES's ability to take advantage of this opportunity to expand its customer base contributed to the increase in natural gas revenues. Expenses Total expenses increased nearly $3.7 billion in 2002, which included more than $3.7 billion of incremental expenses for the former GPU companies in 2002 (twelve months), compared to 2001 (seven weeks). For our pre-merger companies, total expenses increased $295.7 million in 2002 and $280.4 million in 2001, compared to the respective prior years. Sources of changes in pre-merger and post-merger companies' expenses in 2002 and 2001, compared to the prior year, are summarized in the following table: Sources of Expense Changes 2002 2001 ---------------------------------------------------------------- Increase (Decrease) (In millions) Pre-Merger Companies: Fuel and purchased power $ 441.7 $ 48.7 Purchased gas (227.9) 266.5 Other operating expenses 178.5 178.2 Depreciation and amortization (125.1) (99.0) General taxes 28.5 (114.0) ---------------------------------------------------------------- Total Pre-Merger Companies 295.7 280.4 ---------------------------------------------------------------- Former GPU Companies 3,713.8 542.4 Intercompany Expenses (353.9) (32.6) ---------------------------------------------------------------- Net Expense Increase $3,655.6 $ 790.2 ================================================================ The following comparisons reflect variances for the pre-merger companies only, excluding the incremental expenses for the former GPU companies in 2002 and 2001. Higher fuel and purchased power costs in 2002 compared to 2001 primarily reflect additional purchased power costs of $342.2 million. The increase resulted from additional volumes to cover supply obligations assumed by FES. These included a portion of Met-Ed's and Penelec's PLR supply requirements (which started in the third quarter of 2002), contract sales including sales to the New Jersey market to provide BGS, and additional supplies required to replace Davis-Besse power during its extended outage (see Davis-Besse Restoration). Fuel expense increased $99.5 million in 2002 from the prior year principally due to additional internal generation (5.4% higher) and an increased mix of coal and natural gas generation in 2002. The extended outage at the Davis-Besse nuclear plant produced a decline in nuclear generation of 14.6% in 2002, compared to 2001. Purchased gas costs decreased by $227.9 million primarily due to lower unit costs of natural gas purchased in 2002 compared to the prior year resulting in a $48.4 million improvement in gas margins. In 2001, the increase in fuel expense compared to 2000 ($24.3 million) resulted from the substitution of coal and natural gas fired generation for nuclear generation during a period of reduced nuclear availability resulting from both planned and unplanned outages. Higher unit costs for coal consumed also contributed to the increase during that period. Purchased power costs increased early in 2001, compared to 2000, due to higher winter prices and additional purchased power requirements during that period, with the balance of the year offsetting all but $24.4 million of that increase as a result of generally lower prices and reduced external power needs compared to 2000. Purchased gas costs increased 48% in 2001 compared to 2000, principally due to the expansion of FES's retail gas business. Other operating expenses increased $178.5 million in 2002 from the previous year. The increase principally resulted from several large offsetting factors. Nuclear costs increased $125.3 million primarily due to $115.0 million of incremental Davis-Besse costs related to its extended outage (see Davis-Besse Restoration). One-time charges, discussed above, added $98.3 million and an aggregate increase in administrative and general expenses and non-operating costs of $127.4 million resulted in large part from higher employee benefit expenses. Partially offsetting these higher costs were the elimination in the second half of 2001 of coal trading activities ($95.4 million) and reduced facilities service business ($58.9 million). In 2001, other operating expenses increased by $178.2 million compared to the prior year. The significant reduction in 2001 of gains from the sale of emission allowances, higher fossil operating costs and additional employee benefit costs accounted for $144.5 million of the increase in 2001. Additionally, higher operating costs from the competitive services business segment due to expanded operations contributed $56.9 million to the increase. Partially offsetting these higher other operating expenses was a reduction in low-income payment plan customer costs and a $30.2 million decrease in nuclear operating costs in 2001, compared to 2000, resulting from one less refueling outage. Fossil operating costs increased $44.3 million in 2001 from 2000 due principally to planned maintenance work at the Bruce Mansfield generating plant. Pension costs increased by $32.6 million in 2001 from 2000 primarily due to lower returns on pension plan assets (due to significant market-related reductions in the value of pension plan assets), the completion of the 15-year amortization of OE's pension transition asset and changes to plan benefits. Health care benefit costs also increased by $21.4 million in 2001, compared to 2000, principally due to an increase in the health care cost trend rate assumption for computing post-retirement health care benefit liabilities. Charges for depreciation and amortization decreased $125.1 million in 2002 from the preceding year. This decrease resulted from two factors: shopping incentive deferrals and tax-deferrals under the Ohio transition plan ($108.5 million) and the cessation of goodwill amortization ($56.4 million) beginning January 1, 2002. However, several items offset a portion of the above reduction. The start up of a new fluidized bed boiler in January 2002, owned by Bayshore Power Company, a wholly owned subsidiary, resulted in higher depreciation expense in 2002. Also, new combustion turbine capacity added in late 2001 and two months of 2001 depreciation recorded in 2002 (for the four fossil plants we chose not to sell) increased depreciation expense in 2002. In 2001, charges for depreciation and amortization decreased by $99.0 million from the prior year. Approximately $64.6 million of the decrease resulted from lower incremental transition cost amortization under our Ohio transition plan compared to accelerated cost recovery in connection with OE's prior rate plan. The reduction in depreciation and amortization also reflected additional cost deferrals of $51.2 million for recoverable shopping incentives under the Ohio transition plan, partially offset by increases associated with depreciation on completed combustion turbines in the fourth quarter of 2001. General taxes increased $28.5 million in 2002 from 2001 principally due to additional property taxes and the absence in 2002 of a one-time benefit of $15 million resulting from the successful resolution of certain property tax issues in the prior year. In 2001, general taxes declined $114.0 million from 2000 primarily due to reduced property taxes and other state tax changes in connection with the Ohio electric industry restructuring. The reduction in general taxes was partially offset by $66.6 million of new Ohio franchise taxes, which are classified as state income taxes on the Consolidated Statements of Income. Net Interest Charges Net interest charges increased $390.6 million in 2002, compared to 2001. These increases included interest on $4 billion of long-term debt issued by FirstEnergy in connection with the merger. Excluding the results associated with the former GPU companies and merger-related financing, net interest charges decreased $57.0 million in 2002, compared to a $39.8 million decrease in 2001 from 2000. Our continued redemption and refinancing of our outstanding debt and preferred stock during 2002, maintained our downward trend in financing costs, before the effects of the GPU merger. Excluding activities related to the former GPU companies, redemption and refinancing activities for 2002 totaled $1.1 billion and $143.4 million, respectively, and are expected to result in annualized savings of $86.0 million. We also exchanged existing fixed-rate payments on outstanding debt (principal amount of $593.5 million at year end 2002) for short-term variable rate payments through interest rate swap transactions (see Market Risk Information - Interest Rate Swap Agreements below). Net interest charges were reduced by $17.4 million in 2002 as a result of these swaps. Cumulative Effect of Accounting Changes Earnings for 2002 were affected by two accounting changes. As of the merger date certain former GPU international operations were identified as "assets pending sale." Avon and Emdersa were the two remaining operations identified for sale following the completed sale of Australian operations in December 2001. Subsequent to the merger date, results of operations and incremental interest costs related to these international subsidiaries were not included in our Consolidated Statement of Income. On February 6, 2002, discussions began with Aquila, Inc. on modifying its initial offer for the acquisition of Avon, which resulted in a change in accounting for this investment, and a $31.7 million after-tax increase to earnings. Also, as of December 31, 2002, we had not reached a definitive agreement to sell Emdersa. As a result, Emdersa could no longer be considered as "assets pending sale," which resulted in a change in accounting for this investment and an after-tax reduction to earnings of $88.8 million. The amount of this one-time, after-tax charge was comprised of $104.1 million in currency transaction losses arising principally from U. S. dollar denominated debt offset by $15.3 million of operating income. In 2001, we adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" resulting in an $8.5 million after-tax charge. Postretirement Plans Sharp declines in equity markets since the second quarter of 2000 and a reduction in our assumed discount rate in 2001 have combined to produce a negative trend in pension expenses - moving from a net increase to earnings in 2000 and 2001 to a reduction of earnings in 2002. Also, increases in health care payments and a related increase in projected trend rates have led to higher health care costs. The following table presents the pre-tax pension and other post-employment benefits (OPEB) expenses for our pre-merger companies (excluding amounts capitalized): Postretirement Expenses (Income) 2002 2001 2000 ------------------------------------------------------------------ (in millions) Pension $ 16.4 $(11.1) $(40.6) OPEB 99.1 86.6 65.5 - ------------------------------------------------------------------- Total $115.5 $ 75.5 $ 24.9 =================================================================== The pension and OPEB expense increases are included in various cost categories and have contributed to other cost increases discussed above. See "Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement expenses and anticipated pension and OPEB expense increases in 2003. Results of Operations - Business Segments We manage our business as two separate major business segments - regulated services and competitive services. The regulated services segment designs, constructs, operates and maintains our regulated domestic transmission and distribution systems. It also provides generation services to franchise customers who have not chosen an alternative generation supplier. OE, CEI and TE (Ohio Companies) and Penn obtain generation through a power supply agreement with the competitive services segment (see Outlook - Business Organization). The competitive services segment includes all competitive energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation, trading and sourcing of commodity requirements, as well as other competitive energy application services. Competitive products are increasingly marketed to customers as bundled services, often under master contracts. Financial results discussed below include intersegment revenue. A reconciliation of segment financial results to consolidated financial results is provided in Note 8 to the consolidated financial statements. Financial data for 2002 and 2001 for the major business segments include reclassifications to conform with the current business segment organizations and operations, which affect 2002 and 2001 results discussed below. Regulated Services Net income increased to $997.1 million in 2002, compared to $729.1 million in 2001 and $562.5 million in 2000. Excluding additional net income of $312.7 million associated with the former GPU companies, net income decreased by $44.7 million in 2002. The changes in pre-merger net income are summarized in the following table: Regulated Services 2002 2001 ---------------------------------------------------------------------- Increase (Decrease) (In millions) Revenues $(529.5) $(116.4) Expenses (346.6) (344.1) ---------------------------------------------------------------------- Income Before Interest and Income Taxes (182.9) 227.7 ---------------------------------------------------------------------- Net interest charges (128.0) (16.8) Income taxes (10.2) 132.7 ---------------------------------------------------------------------- Net Income Change $ (44.7) $ 111.8 ====================================================================== Lower generation sales, additional transition plan incentives and a slight decline in revenue from distribution deliveries combined for a $312.5 million reduction in external revenues in 2002 from the prior year. Shopping by Ohio customers from alternative energy suppliers combined with the effect of a sluggish national economy on our regional business reduced retail electric sales revenues. In addition, a $188.0 million decline in revenues resulted from reduced sales to FES, due to the extended outage of the Davis-Besse nuclear plant, which reduced generation available for sale. The $346.6 million decrease in expenses resulted from three major factors: a $179.8 million decrease in purchased power, a $35.6 million reduction in other operating expenses and a $141.8 million decrease in depreciation expense. Lower generation sales reduced the need for purchased power and other operating expenses reflected reduced costs in jobbing and contracting work and decreased uncollectible accounts expense. Reduced depreciation and amortization resulted from $108.5 million of new deferred regulatory assets under the Ohio transition plan and the cessation of goodwill amortization beginning January 1, 2002. In 2001, distribution throughput was 1.7% lower, compared to 2000, reducing external revenues by $245.7 million. Partially offsetting the decrease in external revenues were revenues from FES for the rental of fossil generating facilities and the sale of generation from nuclear plants, resulting in a net $116.4 million reduction to total revenues. Expenses were $344.1 million lower in 2001 than 2000 due to lower purchased power, depreciation and amortization and general taxes, offset in part by higher other operating expenses. Lower generation sales reduced the need to purchase power from FES, with a resulting $267.8 million decline in those costs in 2001 from the prior year. Other operating expenses increased by $178.5 million in 2001 from the previous year reflecting a significant reduction in 2001 of gains from the sale of emission allowances, higher fossil operating costs and additional employee benefit costs. Lower incremental transition cost amortization and the new shopping incentive deferrals under our Ohio transition plan as compared with the accelerated cost recovery in connection with OE's prior rate plan in 2000 resulted in a $131.0 million reduction in depreciation and amortization in 2001. A $123.6 million decrease in general taxes in 2001 from the prior year primarily resulted from reduced property taxes and other state tax changes in connection with the Ohio electric industry restructuring. Competitive Services Net losses increased to $119.0 million in 2002, compared to $31.8 million in 2001 and net income of $39.1 million in 2000. Excluding additional net income of $2.6 million associated with the former GPU companies, net losses increased by $89.8 million in 2002. The changes to pre-merger earnings are summarized in the following table: Competitive Services 2002 2001 ---------------------------------------------------------------------- Increase (Decrease) (In millions) Revenues $211.5 $289.3 Expenses 351.1 392.5 ---------------------------------------------------------------------- Income Before Interest and Income Taxes (139.6) (103.2) ---------------------------------------------------------------------- Net interest charges 21.9 13.5 Income taxes (63.2) (51.3) Cumulative effect of a change in accounting 8.5 (8.5) ---------------------------------------------------------------------- Net Loss Increase $ 89.8 $ 73.9 ====================================================================== The $211.5 million increase in revenues in 2002, compared to 2001, represents the net effect of several factors. Revenues from the wholesale electricity market increased $485.3 million in 2002 from the prior year and KWH sales more than doubled. More than half of the increase resulted from additional sales to Met-Ed and Penelec to supply a portion of their PLR supply requirements in Pennsylvania, as well as BGS sales in New Jersey and sales under several other contracts. Retail KWH sales revenues increased $136.4 million as a result of expanding KWH sales within Ohio under Ohio's electricity choice program. Total electric sales revenue increased $621.7 million in 2002 from 2001, accounting for almost all of the net increase in revenues. Offsetting the higher electric sales revenue were reduced natural gas revenues ($171.7 million) primarily due to lower prices and less revenue from FSG ($65.5 million) reflecting the sluggish economy. Internal sales to the regulated services segment decreased $179.8 million in large part due to the impact of customer shopping reducing requirements by the regulated services segment. Expenses increased $351.1 million in 2002 from the prior year, due to additional purchased power ($342.2 million) to supply the incremental KWH sales to wholesale and retail customers. Other operating expenses increased $207.2 million from the prior year as a result of higher nuclear costs due to incremental Davis-Besse costs from its extended outage. One-time charges discussed above increased costs by $75.6 million. Offsetting these increases were reduced purchased gas costs ($227.9 million) primarily resulting from lower prices and reduced costs from FSG reflecting reduced business activity. In 2001, sales to nonaffiliates increased $523.2 million, compared to the prior year, with electric revenues contributing $299.8 million, natural gas revenues adding $226.1 million and the balance of the change from energy-related services. Reduced power requirements by the regulated services segment reduced internal revenues by $267.8 million. Expenses increased $392.5 million in 2002 from 2001 primarily due to a $266.5 million increase in purchased gas costs and increases resulting from additional fuel and purchased power costs (see Results of Operations above) as well as higher expenses for energy-related services. Reduced margins for both major competitive product areas - electricity and natural gas - contributed to the reduction in net income, along with higher interest charges and the cumulative effect of the SFAS 133 accounting change. Margins for electricity and gas sales were both adversely affected by higher fuel costs. Capital Resources and Liquidity Changes in Cash Position The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $1.5 billion of revolving credit facilities, which it can draw upon. In 2002, FirstEnergy received $447 million of cash dividends on common stock from its subsidiaries and paid $440 million in cash dividends on common stock to its shareholders. There are no material restrictions on the issuance of cash dividends by FirstEnergy's subsidiaries. As of December 31, 2002, we had $196.3 million of cash and cash equivalents (including $50 million that redeemed long-term debt in January 2003) on our Consolidated Balance Sheet. This compares to $220.2 million as of December 31, 2001. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Our consolidated net cash from operating activities is provided by our regulated and competitive energy services businesses (see Results of Operations - - Business Segments above). Net cash flows from operating activities in 2002 reflect twelve months of cash flows for the former GPU companies while 2001 includes only seven weeks of those companies' operations (November 7, 2001 to December 31, 2001). Both periods include a full twelve months for the pre-merger companies. Net cash provided from operating activities was $1.915 billion in 2002 and $1.282 billion in 2001. The modest contribution to operating cash flows in 2002 by the former GPU companies reflects in part the deferrals of purchased power costs related to their PLR obligations (see State Regulatory Matters - New Jersey and Pennsylvania below). Cash flows provided from 2002 operating activities of our pre-merger companies and former GPU companies are as follows: Operating Cash Flows 2002 2001 ------------------------------------------------------------- (in millions) Pre-merger Companies: Cash earnings (1) $1,149 $1,551 Working capital and other 315 21 ------------------------------------------------------------- Total pre-merger companies 1,464 1,572 Former GPU companies 563 166 Eliminations (112) (456) ------------------------------------------------------------- Total $1,915 $1,282 ============================================================= (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and major noncash charges. Excluding the former GPU companies, cash flows from operating activities totaled $1.464 billion in 2002 primarily due to cash earnings and to a lesser extent working capital and other changes. In 2001, cash flows from operating activities totaled $1.572 billion principally due to cash earnings. Cash Flows From Financing Activities In 2002, the net cash used for financing activities of $1.123 billion primarily reflects the redemptions of debt and preferred stock shown below. In 2001, net cash provided from financing activities totaled $1.964 billion, primarily due to $4 billion of long-term debt issued in connection with the GPU acquisition, which was partially offset by $2.1 billion of redemptions and refinancings. The following table provides details regarding new issues and redemptions during 2002: Securities Issued or Redeemed 2002 ------------------------------------------------------------- (In millions) New Issues Pollution Control Notes $ 143 Transition Bonds (See Note 5H) 320 Unsecured Notes 210 Other, principally debt discounts (4) ------------------------------------------------------------- $ 669 Redemptions First Mortgage Bonds $ 728 Pollution Control Notes 93 Secured Notes 278 Unsecured Notes 189 Preferred Stock 522 Other, principally redemption premiums 21 ------------------------------------------------------------- $1,831 Short-term Borrowings, Net $ 479 ------------------------------------------------------------- We had approximately $1.093 billion of short-term indebtedness at the end of 2002 compared to $614.3 million at the end of 2001. Available borrowing capability included $177 million under the $1.5 billion revolving lines of credit and $64 million under bilateral bank facilities. At the end of 2002, OE, CEI, TE and Penn had the aggregate capability to issue $2.1 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds. JCP&L, Met-Ed and Penelec will no longer issue FMB other than as collateral for senior notes, since their senior note indentures prohibit them (subject to certain exceptions) from issuing any debt which is senior to the senior notes. As of December 31, 2002, JCP&L, Met-Ed and Penelec had the aggregate capability to issue $474 million of additional senior notes based upon FMB collateral. Based upon applicable earnings coverage tests and their respective charters, OE, Penn, TE and JCP&L could issue a total of $4.3 billion of preferred stock (assuming no additional debt was issued) as of the end of 2002. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock (see Note 5G - Long-Term Debt for discussion of debt covenants). At the end of 2002, our common equity as a percentage of capitalization stood at 38% compared to 35% and 42% at the end of 2001 and 2000, respectively. The lower common equity percentage in 2002 compared to 2000 resulted from the effect of the GPU acquisition. The increase in the 2002 equity percentage from 2001 primarily reflects net redemptions of preferred stock and long-term debt, financed in part by short-term borrowings, and the increase in retained earnings. Cash Flows From Investing Activities Net cash flows used in investing activities totaled $816 million in 2002. The net cash used for investing principally resulted from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Expenditures for property additions by the competitive services segment are principally generation-related including capital additions at the Davis-Besse nuclear plant during its extended outage. The following table summarizes 2002 investments by our regulated services and competitive services segments: Summary of 2002 Cash Flows Property Used for Investing Activities Additions Investments Other Total ---------------------------------------------------------------------------- Uses (Sources) (in millions) Regulated Services $(490) $ 87 $ (21) $(424) Competitive Services (403) -- 10 (393) Other (105) 149* (54) (10) Eliminations -- -- 11 11 ---------------------------------------------------------------------------- Total $(998) $236 $ (54) $(816) ============================================================================= * Includes $155 million of cash proceeds from the sale of Avon (see Note 3). In 2001, net cash flows used in investing activities totaled $3.075 billion, principally due to the GPU acquisition ($2.013 billion) and property additions ($852 million). Our cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, we expect to meet our contractual obligations with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets.
Less than 1-3 3-5 More than Contractual Obligations Total 1 Year Years Years 5 Years - --------------------------------------------------------------------------------------------------------------- (in millions) Long-term debt $12,465 $1,073 $2,210 $1,654 $ 7,528 Short-term borrowings 1,093 1,093 -- -- -- Preferred stock (1) 445 2 4 14 425 Capital leases (2) 31 5 11 7 8 Operating leases (2) 2,697 153 365 349 1,830 Purchases (3) 13,156 2,149 2,902 2,634 5,471 - --------------------------------------------------------------------------------------------------------------- Total $29,887 $4,475 $5,492 $4,658 $15,262 =============================================================================================================== (1) Subject to mandatory redemption (2) See Note 4 (3) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing
Our capital spending for the period 2003-2007 is expected to be about $3.1 billion (excluding nuclear fuel), of which approximately $727 million applies to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $485 million, of which about $69 million applies to 2003. During the same period, our nuclear fuel investments are expected to be reduced by approximately $483 million and $88 million, respectively, as the nuclear fuel is consumed. In May 2002, we sold a 79.9 percent equity interest in Avon, our former wholly owned holding company of Midlands Electricity plc, to Aquila, Inc. (formerly UtiliCorp United) for approximately $1.9 billion (including assumption of $1.7 billion of debt). We received approximately $155 million in cash proceeds and approximately $87 million of long-term notes (representing the present value of $19 million per year to be received over six years beginning in 2003). In the fourth quarter of 2002, we recorded a $50 million charge to reduce the carrying value of our remaining Avon 20.1 percent equity investment. On August 8, 2002, we notified NRG that we were canceling a November 2001 agreement to sell four fossil plants for approximately $1.5 billion ($1.355 billion in cash and $145 million in debt assumption) to NRG because NRG had stated it could not complete the transaction under the original terms of the agreement. In December 2002, we announced that we would retain ownership of the plants after reviewing subsequent bids from other potential buyers. As a result of this decision, we recorded an aggregate charge of $74 million ($43 million, net of tax) in the fourth quarter of 2002, consisting of $57 million ($33 million, net of tax) in non-cash depreciation charges that were not recorded while the plants were pending sale and $17 million ($10 million, net of tax) of transaction-related fees (see Note 3). We did not reach a definitive agreement to sell Emdersa, our Argentina operations, as of December 31, 2002. Therefore, we no longer classified its assets as "Assets Pending Sale" on our Consolidated Balance Sheet and recorded its cumulative results of operations from November 7, 2001 through October 31, 2002 as a one-time, after-tax charge of $88.8 million in our 2002 Consolidated Statement of Income (see Cumulative Effect of Accounting Changes above). In addition, we began recognizing Emdersa's results of operations beginning November 1, 2002 in our consolidated financial statements. We continue to seek opportunities to sell our foreign operations acquired in the 2001 merger with GPU. On February 22, 2002, Moody's Investor Service changed its credit rating outlook for FirstEnergy, Met-Ed and Penelec from stable to negative. The change was based upon a decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania Public Utility Commission (PPUC) for reconsideration its decision on the mechanism for sharing merger savings and reversed the PPUC decisions regarding rate relief and accounting deferrals rendered in connection with its approval of the GPU merger (see Note 2). On March 20, 2002, Moody's changed its outlook for CEI and TE from stable to negative and retained a negative outlook for FirstEnergy based on the uncertain outcome of the Davis-Besse extended outage. On April 4, 2002, Standard & Poor's (S&P) changed its outlook for our credit ratings from stable to negative citing recent developments including: damage to the Davis-Besse reactor vessel head, the Pennsylvania Commonwealth Court decision, and deteriorating market conditions for some sales of our remaining non-core assets. On July 31, 2002, Fitch revised its rating outlook for FirstEnergy, CEI and TE securities to negative from stable. The revised outlook reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's judgment about NRG's financial ability to consummate the purchase of four power plants from FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while NRG's liquidity position added uncertainty to our sale of power plants to NRG, our ratings would not be affected. S&P found our cash flows sufficiently stable to support a continued (although delayed) program of debt and preferred stock redemption. S&P noted that it would continue to closely monitor our progress on various initiatives. On January 21, 2003, S&P indicated its concern about our disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining our current debt ratings. S&P also identified other issues it would continue to monitor including: our deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of our short power position, and continued capture of projected merger savings. While we anticipate being prepared to restart the Davis-Besse plant in the spring of 2003 (see Davis-Besse Restoration below), the Nuclear Regulatory Commission (NRC) must authorize the unit's restart following a formal inspection process prior to our returning the unit to service. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which we reduce debt could put additional pressure on our credit ratings. Other Obligations Obligations not included on our Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are reflected in the operating lease payments disclosed above (see Note 4). The present value as of December 31, 2002, of these sale and leaseback operating lease commitments, net of trust investments, total $1.5 billion. CEI and TE sell substantially all of their retail customer receivables, which provided $170 million of off-balance sheet financing as of December 31, 2002 (see Note 2 - Revenues). Guarantees and Other Assurances As part of normal business activities, we enter into various agreements on behalf of our subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and rating-contingent collateralization provisions. As of December 31, 2002, the maximum potential future payments under outstanding guarantees and other assurances totaled $913 million, as summarized below: Maximum Guarantees and Other Assurances Exposure ----------------------------------------------------------- (In millions) FirstEnergy Guarantees of Subsidiaries: Energy and Energy-Related Contracts(1) $670 Financings (2)(3) 186 -------------------------------------------------------- 856 Surety Bonds 26 Rating-Contingent Collateralization (4) 31 -------------------------------------------------------- Total Guarantees and Other Assurances $913 ======================================================== (1) Issued for a one-year term, with a 10-day termination right by FirstEnergy. (2) Includes parental guarantees of subsidiary debt and lease financing including our letters of credit supporting subsidiary debt. (3) Issued for various terms. (4) Estimated net liability under contracts subject to rating-contingent collateralization provisions. We guarantee energy and energy-related payments of our subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. We also provide guarantees to various providers of subsidiary financings principally for the acquisition of property, plant and equipment. These agreements legally obligate us and our subsidiaries to fulfill the obligations of our subsidiaries directly involved in these energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, our guarantee enables the counterparty's legal claim to be satisfied by our other assets. The likelihood is remote that such parental guarantees will increase amounts otherwise paid by us to meet our obligations incurred in connection with financings and ongoing energy and energy-related contracts. Most of our surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions. Various contracts include credit enhancements in the form of cash collateral, letters of credit or other security in the event of a reduction in credit rating. These provisions vary and typically require more than one rating reduction to below investment grade by S&P or Moody's to trigger additional collateralization. Market Risk Information We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. Our Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk We are exposed to market risk primarily due to fluctuations in electricity, natural gas and coal prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. Most of our non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during 2002 is summarized in the following table:
Increase (Decrease) in the Fair Value of Commodity Derivative Contracts Non-Hedge Hedge Total - ------------------------------------------------------------------------------------------------ (In millions) Outstanding net asset (liability) as of January 1, 2002 $ 9.9 $(76.3) $(66.4) New contract value when entered -- 2.2 2.2 Additions/Increase in value of existing contracts 55.5 73.9 129.4 Change in techniques/assumptions (20.1) -- (20.1) Settled contracts 8.5 24.3 32.8 - ------------------------------------------------------------------------------------------------ Outstanding net asset as of December 31, 2002 (1) 53.8 24.1 77.9 - ------------------------------------------------------------------------------------------------ Non-commodity net assets as of December 31, 2002: Interest Rate Swaps (2) -- 20.5 20.5 - ------------------------------------------------------------------------------------------------ Net Assets - Derivatives Contracts as of December 31, 2002 (3) $ 53.8 $ 44.6 $ 98.4 ================================================================================================ Impact of Changes in Commodity Derivative Contracts (4) Income Statement Effects (Pre-Tax) $ 13.9 $ -- $ 13.9 Balance Sheet Effects: Other Comprehensive Income (OCI) (Pre-Tax) $ -- $ 98.2 $ 98.2 Regulatory Liability $ 30.0 $ -- $ 30.0 (1) Includes $34.2 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Interest rate swaps are primarily treated as fair value hedges. Changes in derivative values of the fair value hedges are offset by changes in the hedged debts' premium or discount (see Interest Rate Swap Agreements below). (3) Excludes $9.3 million of derivative contract fair value decrease, as of December 31, 2002, representing our 50% share of Great Lakes Energy Partners, LLC. (4) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions.
Derivatives included on the Consolidated Balance Sheet as of December 31, 2002: Non-Hedge Hedge Total - ---------------------------------------------------------------------- (In millions) Current- Other Assets $ 31.2 $14.9 $ 46.1 Other Liabilities (16.2) (8.8) (25.0) Non-Current- Other Deferred Charges 39.6 39.4 79.0 Other Deferred Credits (0.8) (0.9) (1.7) --------------------------------------------------------------------- Net assets $ 53.8 $44.6 $ 98.4 ===================================================================== The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. We use these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table:
Source of Information - - Fair Value by Contract Year 2003 2004 2005 2006 Thereafter Total - ----------------------------------------------------------------------------------------------------------- (In millions) Prices actively quoted(1) $16.0 $1.5 $ -- $ -- $ -- $17.5 Other external sources(2) 22.2 2.1 (0.9) -- -- 23.4 - Prices based on models -- -- -- 5.5 31.5 37.0 - ----------------------------------------------------------------------------------------------------------- Total(3) $38.2 $3.6 $(0.9) $5.5 $31.5 $77.9 =========================================================================================================== (1) Exchange traded. (2) Broker quote sheets. (3) Includes $34.2 million from an embedded option that is offset by a regulatory liability and does not affect earnings.
We perform sensitivity analyses to estimate our exposure to the market risk of our commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both our trading and nontrading derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2002. We estimate that if energy commodity prices experienced an adverse 10% change, net income for the next twelve months would decrease by approximately $3.7 million. Interest Rate Risk Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the table below. We are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 4 to the consolidated financial statements, our investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk. Changes in the market value of our nuclear decommissioning trust funds had been recognized by making corresponding changes to the decommissioning liability, as described in Note 2 to the consolidated financial statements. In conjunction with the adoption of SFAS 143 "Accounting for Asset Retirement Obligations," on January 1, 2003, we reclassified unrealized gains or losses to OCI in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity." While fluctuations in the fair value of our Ohio EUOCs' trust balances will eventually affect earnings (affecting OCI initially) based on the guidance provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from customers the difference between the investments held in trust and their decommissioning obligations. Thus, in absence of disallowed costs, there should be no earnings effect from fluctuations in their decommissioning trust balances. As of December 31, 2002, decommissioning trust balances totaled $1.050 billion, with $698 million held by our Ohio EUOC and the balance held by our non-Ohio EUOC. As of year end 2002, trust balances included 51% of equity and 49% of debt instruments.
Comparison of Carrying Value to Fair Value - ----------------------------------------------------------------------------------------------------------------------- There- Fair Year of Maturity 2003 2004 2005 2006 2007 after Total Value - ----------------------------------------------------------------------------------------------------------------------- (Dollars in millions) - ----------------------------------------------------------------------------------------------------------------------- Assets Investments other than Cash and Cash Equivalents-Fixed Income $ 115 $327 $ 72 $ 90 $ 85 $1,843 $ 2,532 $ 2,638 Average interest rate 7.5% 7.8% 8.1% 8.1% 8.2% 6.3% 6.8% - ----------------------------------------------------------------------------------------------------------------------- _______________________________________________________________________________________________________________________ Liabilities Long-term Debt: Fixed rate $ 964 $939 $867 $1,401 $252 $6,386 $10,809 $11,119 Average interest rate 7.7% 7.2% 8.1% 5.7% 6.7% 7.0% 7.0% Variable rate $ 109 $399 $ 5 $ 1 $1,142 $ 1,656 $ 1,642 Average interest rate 5.4% 2.6% 6.7% 6.1% 2.7% 2.9% Short-term Borrowings $1,093 $ 1,093 $ 1,093 Average interest rate 2.4% 2.4% - ----------------------------------------------------------------------------------------------------------------------- Preferred Stock $ 2 $ 2 $ 2 $ 2 $ 12 $ 425 $ 445 $ 454 Average dividend rate 7.5% 7.5% 7.5% 7.5% 7.6% 8.1% 8.1% - -----------------------------------------------------------------------------------------------------------------------
Interest Rate Swap Agreements During 2002, FirstEnergy entered into fixed-to-floating interest rate swap agreements, to increase the variable-rate component of its debt portfolio from 16% to approximately 20% at year end. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options and interest payment dates match those of the underlying obligations. During the fourth quarter of 2002, in a period of steadily declining market interest rates, we unwound swaps with a total notional amount of $400 million that we had entered into during the second and third quarters of 2002. Under fair-value accounting, the swaps' fair value ($19.9 million asset) was added to the carrying value of the hedged debt and will be amortized to maturity. Offsets to interest expense recorded in 2002 due to the difference between fixed and variable debt rates totaled $17.4 million. As of December 31, 2002, the debt underlying FirstEnergy's outstanding interest rate swaps had a weighted average fixed interest rate of 7.76%, which the swaps have effectively converted to a current weighted average variable interest rate of 3.04%. GPU Power (through a subsidiary) used dollar-denominated interest rate swap agreements in 2002. In 2001, Penelec, GPU Power (through a subsidiary) and GPU Electric, Inc. (through GPU Power UK) used interest rate swaps denominated in dollars and sterling. All of the agreements of the former GPU companies convert variable-rate debt to fixed-rate debt to manage the risk of increases in variable interest rates. GPU Power's swaps had a weighted average fixed interest rate of 6.68% in 2002 and 6.99% in 2001. The following summarizes the principal characteristics of the swap agreements:
Interest Rate Swaps ------------------- December 31, 2002 December 31, 2001 ---------------------------- ----------------------------- Notional Maturity Fair Notional Maturity Fair Denomination Amount Date Value Amount Date Value -------------------------------------------------------------------------------------------- (dollars/sterling in millions) Fixed-to-Floating Rate Dollar 444 2023 15.5 150 2025 5.9 Floating to Fixed Rate Dollar 16 2005 (0.9) 50 2002 (1.8) 26 2005 (1.1) Sterling 125 2003 (2.3) - ----------------------------------------------------------------------------------------------
Equity Price Risk Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $532 million and $568 million as of December 31, 2002 and 2001, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges, would result in a $53 million reduction in fair value as of December 31, 2002 (see Note 2J - Supplemental Cash Flows Information). Foreign Currency Risk We are exposed to foreign currency risk from investments in international business operations acquired through the merger with GPU. While such risks are likely to diminish over time as we sell our international operations, we expect such risks to continue in the near term. In 2002, we experienced net foreign currency translation losses in connection with our Argentina operations (see Note 3 - Divestitures). A hypothetical 20% adverse change in our foreign currency positions in the near term would not have had a material effect on our consolidated financial position, cash flows or earnings as of December 31, 2002. Outlook We continue to pursue our goal of being the leading regional supplier of energy and related services in the northeastern quadrant of the United States, where we see the best opportunities for growth. We believe that our strategy has received some measure of validation by the major industry events of 2002 and we continue to build toward a strong regional presence. We intend to provide competitively priced, high-quality products and value-added services - energy sales and services, energy delivery, power supply and supplemental services related to our core business. As our industry changes to a more competitive environment, we have taken and expect to take actions designed to create a larger, stronger regional enterprise that will be positioned to compete in the changing energy marketplace. Business Organization Beginning in 2001, Ohio utilities that offered both competitive and regulated retail electric services were required to implement a corporate separation plan approved by the Public Utilities Commission of Ohio (PUCO) - one which provided a clear separation between regulated and competitive operations. Our business is separated into three distinct units - a competitive services segment, a regulated services segment and a corporate support segment. FES provides competitive retail energy services while the EUOC continue to provide regulated transmission and distribution services. FirstEnergy Generation Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOCs and operates those plants. We expect the transfer of ownership of EUOC non-nuclear generating assets to FGCO will be substantially completed by the end of the market development period in 2005. All of the EUOC power supply requirements for the Ohio Companies and Penn are provided by FES to satisfy their PLR obligations, as well as grandfathered wholesale contracts. Optimizing the Use of Assets A significant step toward being the leading regional supplier in our target market was achieved when we merged with GPU in November 2001, making us the fourth largest investor-owned electric system in the nation based on the number of customers served. Through the merger we are creating a stronger enterprise with greater resources and more opportunities to provide value to our customers, shareholders and employees. However, additional steps must be taken in order to deliver the full value of the merger. While GPU's former domestic electric utility companies fit well with our regional market focus, GPU's former international companies do not. In December 2001, we divested GasNet, an Australian natural gas transmission company. In May 2002, we sold a 79.9 percent interest in Avon's UK operations to Aquila for approximately $1.9 billion. We and Aquila together own all of the outstanding shares of Avon through a jointly owned subsidiary, with each company having a 50-percent voting interest. On August 8, 2002, we notified NRG that we were canceling our agreement with it for its purchase of four fossil plants because NRG had stated that it could not complete the sale transaction under the original terms of the agreement. Based on subsequent bids received, we concluded that retaining the plants to serve our customers was in the best interest of our customers and our shareholders. Following our decision to retain the four plants, we performed a comprehensive fossil operations review and subsequently decided to close the Ashtabula C-Plant (three 44 megawatt (MW), coal-fired boilers). This action is part of our strategy to provide competitively priced energy - replacing less-efficient peaking generation in our portfolio of generation resources, with the development of new, higher-efficiency peaking plants. While deteriorating economic conditions in Argentina delayed our sale of Emdersa, we continue to pursue the sale of assets that do not support our strategy in order to increase our financial flexibility by reducing debt and preferred stock. State Regulatory Matters In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in our EUOCs' respective state regulatory plans. However, despite these similarities, the specific approach taken by each state and for each of our EUOCs varies. Those provisions include: o allowing the EUOC's electric customers to select their generation suppliers; o establishing PLR obligations to non-shopping customers in the EUOC's service areas; o allowing recovery of potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; o itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; o deregulating the EUOC's electric generation businesses; and o continuing regulation of the EUOC's transmission and distribution systems. Regulatory assets are costs which the respective regulatory agencies have authorized for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of the regulatory assets are expected to continue to be recovered under the provisions of the respective transition and regulatory plans as discussed below. The regulatory assets of the individual companies are as follows: Regulatory Assets as of December 31, - -------------------------------------------------------- Company 2002 2001 - ------- -------------------------- (In millions) OE $1,855.9 $2,025.4 CEI 939.8 874.5 TE 392.6 388.8 Penn 156.9 208.8 JCP&L 3,199.0 3,324.8 Met-Ed 1,179.1 1,320.5 Penelec 599.7 769.8 - -------------------------------------------------------- Total $8,323.0 $8,912.6 ======================================================== Ohio FirstEnergy's transition plan (which we filed on behalf of the Ohio Companies) included approval for recovery of transition costs, including regulatory assets, as filed in the transition plan through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The approved plan also granted preferred access over our subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 MW of generation capacity through 2005 at established prices for sales to the Ohio Companies' retail customers. Customer prices are frozen through a five-year market development period (2001-2005), except for certain limited statutory exceptions including a 5% reduction in the price of generation for residential customers. In February 2003, the Ohio Companies were authorized increases in 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. Our 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). That goal was achieved in 2002. Accordingly, FirstEnergy does not believe that there will be any regulatory action reducing the recoverable transition costs. New Jersey 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 New Jersey Board of Public Utilities (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 market transition charge (MTC) and societal benefits charge (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 below. Hearings began in February 2003. The Administrative Law Judge's recommended decision is due in June 2003 and the NJBPU's subsequent decision is due in July 2003. JCP&L's regulatory plan provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. A February 2002 NJBPU order authorized JCP&L to issue $320 million of transition bonds to securitize the recovery of these costs and 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 a wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 -- that debt is recognized on the Consolidated Balance Sheet (see Note 5). 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. 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 results of the February 2002 auction, with the NJBPU's approval, removed JCP&L's BGS obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In February 2003, the auctioning of BGS for the period beginning August 1, 2003 took place. 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 cost balances. Pennsylvania Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to FES through a wholesale power sale which expires in December 2003 and may be extended for each successive calendar year. Under the terms of the wholesale agreement, FES assumed 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 to FES. FES has hedged most of Met-Ed's and Penelec's unfilled PLR obligation through 2005. Met-Ed and Penelec will continue to defer those cost differences between NUG contract rates and the rates reflected in their capped generation rates. In its February 21, 2002 decision on Petitions for Review regarding the June 2001 PPUC orders which approved the FirstEnergy/GPU merger and provided Met-Ed and Penelec deferral accounting treatment for energy costs, the Commonwealth Court of Pennsylvania affirmed the PPUC merger decision, 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 denied the companies authority to defer for future recovery 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 in March 2002, asking it to review the Commonwealth Court decision. In September 2002, FirstEnergy established reserves against 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) for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred pre-merger 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 Commonwealth Court's 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, FirstEnergy, Met-Ed and Penelec believe that the disallowance of competitive transition charge recovery of PLR costs above Met-Ed's and Penelec's capped generation rates will not have a future adverse financial impact. FERC Regulatory Matters On December 19, 2002, the Federal Energy Regulatory Commission (FERC) granted unconditional Regional Transmission Organization status to PJM Interconnection, LLC which includes JCP&L, Met-Ed and Penelec as transmission owners. Also, on December 19, 2002, the FERC conditionally accepted GridAmerica's filing to become an independent transmission company within Midwest Independent System Operator, Inc. (MISO). GridAmerica will operate ATSI's transmission facilities. GridAmercia expects to begin operations in the second quarter of 2003 subject to approval of certain compliance filings with the FERC. Compliance filings were made by the GridAmerica companies (including ATSI) on January 31 and February 19, 2003. Supply Plan We are obligated to provide generation service for an estimated 2003 peak demand of 18,450 MW. These obligations arise from customers who have elected to continue to receive generation service from the EUOCs under regulated retail rate tariffs and from customers who have selected FES as their alternate generation provider. Geographically, approximately 11,000 MW of the obligations are in the East Central Area Reliability Agreement market and 7,450 MW are in the PJM ISO market area. These obligations include approximately 1,700 MW of load that FES obtained in New Jersey's BGS auction. Additionally, if alternative suppliers fail to deliver power to their customers located in the EUOCs' service areas, we could be required to serve an additional 1,400 MW as PLR. In the event we must procure replacement power for an alternative supplier, the cost of that power would be recovered under the applicable state regulatory rules. To meet their obligations, our subsidiaries have 13,101 MW of installed generating capacity, 1,540 MW of long-term power purchase contracts (exceeding one year), 2,800 MW under short-term purchase contracts and approximately 800 MW of interruptible and controllable load contracts. Any additional power requirements will be satisfied through spot market purchases. All utilities in New Jersey are required to participate in an annual auction through which the entire obligation for all of their BGS requirements are auctioned to alternate suppliers. Through this auction process, the 286 MW of JCP&L's installed capacity and approximately 800 MW of long-term purchases from NUGs are made available to the winning bidders. FES participates in this annual auction as an alternate supplier and currently has an obligation to provide 1,700 MW of power for summer peak demand through July 31, 2003. Davis-Besse Restoration On April 30, 2002, the NRC initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, we have made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. We are also accelerating maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, we discussed plans to test the bottom of the reactor for leaks and to install a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. We anticipate that the unit will be ready for restart in the spring of 2003 after completion of the additional maintenance work and regulatory reviews. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed our plans to reduce post-merger debt levels we believe such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). The actual costs (capital and expense) associated with the extended Davis-Besse outage in 2002 and estimated costs in 2003 are: Costs of Davis-Besse Extended Outage ----------------------------------------------------------------- (In millions) 2002 - Actual ------------- Capital Expenditures: Reactor head and restart $ 63.3 Incremental Expenses (pre-tax): Maintenance $115.0 Fuel and purchased power 119.5 ------ Total $234.5 ====== 2003 - Estimated ---------------- Primarily operating expenses (pre-tax): Maintenance (including acceleration of programs) $50 Replacement power per month $12-18 --------------------------------------------------------------- We have fully hedged the on-peak replacement energy supply for Davis-Besse through the spring of 2003 and have completed some hedging for the balance of 2003 as well. Environmental Matters We believe we are in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 7D - Environmental Matters). We continue to evaluate our compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W.H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against 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 (CAA). The civil complaint against OE and Penn requests installation of "best available control technology" as well as civil penalties of up to $27,500 per day. Although unable to predict the outcome of these proceedings, we believe the Sammis Plant is in full compliance with the CAA and that the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. 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 the SBC. The Companies have total accrued liabilities aggregating approximately $54.3 million as of December 31, 2002. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on our earnings and competitive position. These environmental regulations affect our earnings and competitive position to the extent we compete with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. We believe we are in material compliance with existing regulations, but are unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against FirstEnergy and its subsidiaries. The most significant are described below. Due to our merger with GPU, we own Unit 2 of the Three Mile Island Nuclear Plant (TMI-2). As a result of the 1979 TMI-2 accident, claims for alleged personal injury against JCP&L, Met-Ed, Penelec and GPU had been filed in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by the GPU companies and dismissed the ten initial "test cases" which had been selected for a test case trial. On January 15, 2002, the District Court granted our motion for summary judgment on the remaining 2,100 pending claims. On February 14, 2002, the plaintiffs filed a notice of appeal of this decision (see Note 7E - Other Legal Proceedings). In December 2002, the Court of Appeals for the Third Circuit refused to hear the appeal which effectively ended further legal action for those claims. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service areas of many electric utilities, including JCP&L. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies seeking compensatory and punitive damages arising from the service interruptions of July 1999 in the JCP&L territory. In May 2001, the court denied without prejudice the defendant's motion seeking decertification of the class. Discovery continues in the class action, but no trial date has been set. In October 2001, the court held argument on the plaintiffs' motion for partial summary judgment, which contends that JCP&L is bound to several findings of the NJBPU investigation. The plaintiffs' motion was denied by the Court in November 2001 and the plaintiffs' motion seeking permission to file an appeal on this denial of their motion was rejected by the New Jersey Appellate Division. We have also filed a motion for partial summary judgment that is currently pending before the Superior Court. We are unable to predict the outcome of these matters. Implementation of Recent Accounting Standard In June 2002, the Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Based on the EITF's partial consensus position, for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour (KWH) sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. We have previously reported such contracts as gross revenues and purchased power costs. Comparative quarterly disclosures and the Consolidated Statements of Income for revenues and expenses have been reclassified for 2002 only to conform with the revised presentation (see Note 11 - Summary of Quarterly Financial Data). In addition, the related KWH sales and purchases statistics described above under Results of Operations were reclassified (7.2 billion KWH in 2002 and 3.7 billion KWH in 2001). The following table displays the impact of changing to a net presentation for our energy trading operations. 2002 Impact of Recording Energy Trading Net Revenues Expenses --------------------------------------------------------------------------- (in millions) Total before adjustment $12,420 $10,238 Adjustment (268) (268) --------------------------------------------------------------------------- Total as reported $12,152 $9 ,970 =========================================================================== Significant Accounting Policies We prepare our consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Our more significant accounting policies are described below. Purchase Accounting - Acquisition of GPU Purchase accounting requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities for GPU were based primarily on estimates. The more significant of these included the estimation of the fair value of the international operations, certain domestic operations and the fair value of the pension and other post-retirement benefit assets and liabilities. The purchase price allocations for the GPU acquisition were finalized in the fourth quarter of 2002 (see Note 12). Regulatory Accounting Our regulated services segment is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in each state in which we operate, a significant amount of regulatory assets have been recorded - $8.3 billion as of December 31, 2002. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. We continually monitor our derivative contracts to determine if our activities, expectations, intentions, assumptions and estimates remain valid. As part of our normal operations, we enter into significant commodity contracts, as well as interest rate and currency swaps, which increase the impact of derivative accounting judgments. Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for KWH that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of KWH usage by residential, commercial and industrial customers o KWH usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as our merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, we reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000. Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. The market values of our pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002, 2001 and 2000, plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, we will not be required to fund our pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to our 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. The effect on our SFAS 87 and 106 costs and liabilities from changes in key assumptions are as follows: Increase in Costs from Adverse Changes in Key Assumptions ------------------------------------------------------------------------------ Assumption Adverse Change Pension OPEB Total ------------------------------------------------------------------------------ (In millions) Discount rate Decrease by 0.25% $10.3 $ 7.4 $17.7 Long-term return on assets Decrease by 0.25% $ 6.9 $ 1.2 $ 8.1 Health care trend rate Increase by 1% na $20.7 $20.7 Increase in Minimum Liability ----------------------------- Discount rate Decrease by 0.25% $99.4 na $99.4 ------------------------------------------------------------------------------ As a result of the reduced market value of our pension plan assets, we were required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. We eliminated our prepaid pension asset of $286.9 million and established a minimum liability of $548.6 million, recording an intangible asset of $78.5 million and reducing OCI by $444.2 million (recording a related deferred tax benefit of $312.8 million). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002 increased due to the lower discount rate assumed and reduced market value of plan assets as of December 31, 2002. Our non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $125 million and $45 million, respectively - a total of $170 million in 2003 as compared to 2002. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset, is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur we would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill -- fair value was higher than carrying value for each of our reporting units. The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. As of December 31, 2002, we had $5.9 billion of goodwill that primarily relates to our regulated services segment. Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- SFAS 143, "Accounting for Asset Retirement Obligations" In June 2001, the FASB issued SFAS 143. The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize regulatory assets or liabilities if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. We have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $807 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $437 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144. No impairment was indicated. The asset retirement liability at the date of adoption was $1.109 billion. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.232 billion, including unrealized gains on decommissioning trust funds of $12 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that substantially all nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn will be recoverable through their regulated rates. Therefore, we recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $298 million increase to income ($174 million net of tax). The $12 million of unrealized gains ($7 million net of tax) included in the decommissioning liability balances as of December 31, 2002, were offset against OCI upon adoption of SFAS 143. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities" This statement, which was issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time they are incurred rather than when management commits to a plan of exit or disposal. It also requires the use of fair value for the measurement of such liabilities. The new standard supersedes guidance provided by EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring)." This new standard was effective for exit and disposal activities initiated after December 31, 2002. Since it is applied prospectively, there will be no impact upon adoption. However, SFAS 146 could change the timing and amount of costs recognized in connection with future exit or disposal activities. SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure" SFAS 148 provides alternative approaches for voluntarily transitioning to the fair value method of accounting for stock-based compensation as described by SFAS 123 "Accounting for Stock-Based Compensation." Under current GAAP, we do not intend to adopt fair value accounting. It also amends SFAS 123 disclosure requirements for those companies applying APB 25, "Accounting for Stock Issued to Employees" and FASB Interpretation 44, "Accounting for Transactions involving Stock Compensation - an interpretation of APB Opinion No. 44." The amendment requires prominent display of differences between the SFAS 123 fair-value approach and the intrinsic-value approach described by APB 25 in a prescribed format. SFAS 148 also amends APB 28, "Interim Financial Reporting," to require that these disclosures be made on an interim basis. The new disclosure requirements are effective for 2002 year-end reporting (see Note 2B - Earnings Per Share) and for quarterly reporting beginning in 2003. Application of the alternative transition approaches is effective in 2003. FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002 (see Guarantees and Other Assurances). It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements, the sale of preferred securities and debt secured by bondable property, which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. We currently consolidate the majority of these entities and believe we will continue to consolidate following the adoption of FIN 46. In addition to the entities we are currently consolidating we believe that the PNBV Capital Trust, which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of OE's interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require consolidation. Ownership of the trust includes a three-percent equity interest by a nonaffiliated party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46 would change the characterization of the PNBV trust investment to a lease obligation bond investment. Also, consolidation of the outside minority interest would be required, which would increase assets and liabilities by $12.0 million.
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2002 2001 2000 - --------------------------------------------------------------------------------------------------------------------- (In thousands, except per share amounts) REVENUES: Electric utilities.................................................... $ 9,165,805 $5,729,036 $5,421,668 Unregulated businesses................................................ 2,986,192 2,270,326 1,607,293 ----------- ---------- ---------- Total revenues.................................................... 12,151,997 7,999,362 7,028,961 ----------- ---------- ---------- EXPENSES: Fuel and purchased power.............................................. 3,673,610 1,421,525 1,110,845 Purchased gas......................................................... 592,116 820,031 553,548 Other operating expenses.............................................. 3,947,855 2,727,794 2,378,296 Provision for depreciation and amortization........................... 1,105,904 889,550 933,684 General taxes......................................................... 650,329 455,340 547,681 ----------- ---------- ---------- Total expenses.................................................... 9,969,814 6,314,240 5,524,054 ----------- ---------- ---------- INCOME BEFORE INTEREST AND INCOME TAXES.................................. 2,182,183 1,685,122 1,504,907 ----------- ---------- ---------- NET INTEREST CHARGES: Interest expense...................................................... 891,833 519,131 493,473 Capitalized interest.................................................. (24,474) (35,473) (27,059) Subsidiaries' preferred stock dividends............................... 78,947 72,061 62,721 ----------- ---------- ---------- Net interest charges.............................................. 946,306 555,719 529,135 ----------- ---------- ---------- INCOME TAXES............................................................. 549,476 474,457 376,802 ----------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES.................................................... 686,401 654,946 598,970 ----------- ---------- ---------- CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF INCOME TAXES (BENEFIT) OF $13,600,000 AND ($5,839,000), RESPECTIVELY) (Notes 2J and 3)........................................ (57,121) (8,499) -- ----------- ---------- ---------- NET INCOME............................................................... $ 629,280 $ 646,447 $ 598,970 =========== ========== ========== BASIC EARNINGS PER SHARE OF COMMON STOCK (Note 2J): Income before cumulative effect of accounting changes................. $2.34 $2.85 $2.69 Cumulative effect of accounting changes (Notes 2J and 3).............. (.19) (.03) -- ----- ----- ----- Net income............................................................ $2.15 $2.82 $2.69 ===== ===== ===== WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING...................... 293,194 229,512 222,444 ======= ======= ======= DILUTED EARNINGS PER SHARE OF COMMON STOCK (Note 2J): Income before cumulative effect of accounting changes................. $2.33 $2.84 $2.69 Cumulative effect of accounting changes (Notes 2J and 3).............. (.19) (.03) -- ----- ----- ----- Net income............................................................ $2.14 $2.81 $2.69 ===== ===== ===== WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING.................... 294,421 230,430 222,726 ======= ======= ======= DIVIDENDS DECLARED PER SHARE OF COMMON STOCK............................. $1.50 $1.50 $1.50 ===== ===== ===== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS As of December 31, 2002 2001 - --------------------------------------------------------------------------------------------------------------------- (In thousands) ASSETS CURRENT ASSETS: Cash and cash equivalents.......................................................... $ 196,301 $ 220,178 Receivables- Customers (less accumulated provisions of $52,514,000 and $65,358,000, respectively, for uncollectible accounts)...................................... 1,153,486 1,074,664 Other (less accumulated provisions of $12,851,000 and $7,947,000, respectively, for uncollectible accounts)...................................... 473,106 473,550 Materials and supplies, at average cost- Owned............................................................................ 253,047 256,516 Under consignment................................................................ 174,028 141,002 Prepayments and other.............................................................. 203,630 336,610 ----------- ----------- 2,453,598 2,502,520 ----------- ----------- ASSETS PENDING SALE (Note 3).......................................................... -- 3,418,225 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT: In service......................................................................... 20,372,224 19,981,749 Less--Accumulated provision for depreciation....................................... 8,551,427 8,161,022 ----------- ----------- 11,820,797 11,820,727 Construction work in progress...................................................... 859,016 607,702 ----------- ----------- 12,679,813 12,428,429 ----------- ----------- INVESTMENTS: Capital trust investments (Note 4)................................................. 1,079,435 1,166,714 Nuclear plant decommissioning trusts............................................... 1,049,560 1,014,234 Letter of credit collateralization (Note 4)........................................ 277,763 277,763 Pension investments (Note 2I)...................................................... -- 273,542 Other.............................................................................. 918,874 898,311 ----------- ----------- 3,325,632 3,630,564 ----------- ----------- DEFERRED CHARGES: Regulatory assets.................................................................. 8,323,001 8,912,584 Goodwill........................................................................... 5,896,292 5,600,918 Other (Note 2I).................................................................... 902,437 858,273 ----------- ----------- 15,121,730 15,371,775 ----------- ----------- $33,580,773 $37,351,513 =========== =========== LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt and preferred stock............................... $ 1,702,822 $ 1,867,657 Short-term borrowings (Note 6)..................................................... 1,092,817 614,298 Accounts payable................................................................... 918,268 704,184 Accrued taxes...................................................................... 456,178 418,555 Other.............................................................................. 1,000,415 1,064,763 ----------- ----------- 5,170,500 4,669,457 ----------- ----------- LIABILITIES RELATED TO ASSETS PENDING SALE (Note 3)................................... -- 2,954,753 ----------- ----------- CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholders' equity........................................................ 7,120,049 7,398,599 Preferred stock of consolidated subsidiaries- Not subject to mandatory redemption.............................................. 335,123 480,194 Subject to mandatory redemption.................................................. 18,521 65,406 Subsidiary-obligated mandatorily redeemable preferred securities (Note 5F)......... 409,867 529,450 Long-term debt..................................................................... 10,872,216 11,433,313 ----------- ----------- 18,755,776 19,906,962 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes.................................................. 2,367,997 2,684,219 Accumulated deferred investment tax credits........................................ 235,758 260,532 Nuclear plant decommissioning costs................................................ 1,254,344 1,201,599 Power purchase contract loss liability............................................. 3,136,538 3,566,531 Retirement benefits................................................................ 1,564,930 838,943 Other.............................................................................. 1,094,930 1,268,517 ----------- ----------- 9,654,497 9,820,341 ----------- ----------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 4 and 7)............................. ----------- ----------- $33,580,773 $37,351,513 =========== =========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------ (Dollars in thousands, except per share amounts) COMMON STOCKHOLDERS' EQUITY: Common stock, $0.10 par value - authorized 375,000,000 shares- 297,636,276 shares outstanding....................................................... $ 29,764 $ 29,764 Other paid-in capital.................................................................. 6,120,341 6,113,260 Accumulated other comprehensive loss (Note 5I)......................................... (663,236) (169,003) Retained earnings (Note 5A)............................................................ 1,711,457 1,521,805 Unallocated employee stock ownership plan common stock- 3,966,269 and 5,117,375 shares, respectively (Note 5B)............................... (78,277) (97,227) ----------- ----------- Total common stockholders' equity.................................................... 7,120,049 7,398,599 ----------- ----------- Number of Shares Optional Outstanding Redemption Price ---------------- ----------------------- 2002 2001 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES (Note 5D): Ohio Edison Company Cumulative, $100 par value- Authorized 6,000,000 shares Not Subject to Mandatory Redemption: 3.90%.............................. 152,510 152,510 $103.63 $ 15,804 15,251 15,251 4.40%.............................. 176,280 176,280 108.00 19,038 17,628 17,628 4.44%.............................. 136,560 136,560 103.50 14,134 13,656 13,656 4.56%.............................. 144,300 144,300 103.38 14,917 14,430 14,430 --------- ---------- -------- ----------- ----------- 609,650 609,650 63,893 60,965 60,965 --------- ---------- -------- ----------- ----------- Cumulative, $25 par value- Authorized 8,000,000 shares Not Subject to Mandatory Redemption: 7.75%.............................. -- 4,000,000 -- -- -- 100,000 --------- ---------- -------- ----------- ----------- Total Not Subject to Mandatory Redemption............... 609,650 4,609,650 $ 63,893 60,965 160,965 ========= ========== ======== ----------- ----------- Pennsylvania Power Company Cumulative, $100 par value- Authorized 1,200,000 shares Not Subject to Mandatory Redemption: 4.24%.............................. 40,000 40,000 103.13 $ 4,125 4,000 4,000 4.25%.............................. 41,049 41,049 105.00 4,310 4,105 4,105 4.64%.............................. 60,000 60,000 102.98 6,179 6,000 6,000 7.75%.............................. 250,000 250,000 -- -- 25,000 25,000 --------- ---------- -------- ----------- ----------- Total Not Subject to Mandatory Redemption......................... 391,049 391,049 $ 14,614 39,105 39,105 ========= ========== ======== ----------- ----------- Subject to Mandatory Redemption (Note 5E): 7.625%............................. 142,500 150,000 103.81 $ 14,793 14,250 15,000 Redemption Within One Year........... (750) (750) --------- ---------- -------- ----------- ----------- Total Subject to Mandatory Redemption ....................... 142,500 150,000 $ 14,793 13,500 14,250 ========= ========== ======== ----------- ----------- Cleveland Electric Illuminating Company Cumulative, without par value- Authorized 4,000,000 shares Not Subject to Mandatory Redemption: $ 7.40 Series A................... 500,000 500,000 101.00 $ 50,500 50,000 50,000 $ 7.56 Series B................... -- 450,000 -- -- -- 45,071 Adjustable Series L................ 474,000 474,000 100.00 47,400 46,404 46,404 $42.40 Series T.................... -- 200,000 -- -- -- 96,850 --------- ---------- -------- ----------- ----------- 974,000 1,624,000 97,900 96,404 238,325 Redemption Within One Year........... -- (96,850) --------- ---------- -------- ----------- ----------- Total Not Subject to Mandatory Redemption......................... 974,000 1,624,000 $ 97,900 96,404 141,475 ========= ========== ======== ----------- ----------- Subject to Mandatory Redemption (Note 5E): $ 7.35 Series C................... 60,000 70,000 101.00 $ 6,060 6,021 7,030 $90.00 Series S.................... -- 17,750 -- -- -- 17,268 --------- ---------- -------- ----------- ----------- 60,000 87,750 6,060 6,021 24,298 Redemption Within One Year........... (1,000) (18,010) --------- ---------- -------- ----------- ----------- Total Subject to Mandatory Redemption ....................... 60,000 87,750 $ 6,060 5,021 6,288 ========= ========== ======== ----------- -----------
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd) As of December 31, 2002 2001 - ---------------------------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) Number of Shares Optional Outstanding Redemption Price ---------------- ---------------------- 2002 2001 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK OF CONSOLIDATED SUBSIDIARIES (Cont'd) Toledo Edison Company Cumulative, $100 par value- Authorized 3,000,000 shares Not Subject to Mandatory Redemption: $ 4.25............................. 160,000 160,000 $104.63 $ 16,740 $ 16,000 $ 16,000 $ 4.56............................. 50,000 50,000 101.00 5,050 5,000 5,000 $ 4.25............................. 100,000 100,000 102.00 10,200 10,000 10,000 $ 8.32............................. -- 100,000 -- -- -- 10,000 $ 7.76............................. -- 150,000 -- -- -- 15,000 $ 7.80............................. -- 150,000 -- -- -- 15,000 $10.00.............................. -- 190,000 -- -- -- 19,000 --------- ---------- -------- ----------- ----------- 310,000 900,000 31,990 31,000 90,000 Redemption Within One Year........... -- (59,000) --------- ---------- -------- ----------- ----------- 310,000 900,000 31,990 31,000 31,000 --------- ---------- -------- ----------- ----------- Cumulative, $25 par value- Authorized 12,000,000 shares Not Subject to Mandatory Redemption: $2.21.............................. -- 1,000,000 -- -- -- 25,000 $2.365............................. 1,400,000 1,400,000 27.75 38,850 35,000 35,000 Adjustable Series A................ 1,200,000 1,200,000 25.00 30,000 30,000 30,000 Adjustable Series B................ 1,200,000 1,200,000 25.00 30,000 30,000 30,000 --------- ---------- -------- ----------- ----------- 3,800,000 4,800,000 98,850 95,000 120,000 Redemption Within One Year........... -- (25,000) --------- ---------- -------- ----------- ----------- 3,800,000 4,800,000 98,850 95,000 95,000 --------- ---------- -------- ----------- ----------- Total Not Subject to Mandatory Redemption....................... 4,110,000 5,700,000 $130,840 126,000 126,000 ========= ========== ======== ----------- ----------- Jersey Central Power & Light Company Cumulative, $100 stated value- Authorized 15,600,000 shares Not Subject to Mandatory Redemption: 4.00% Series....................... 125,000 125,000 106.50 $ 13,313 12,649 12,649 ========= ========== ======== ----------- ----------- Subject to Mandatory Redemption: 8.65% Series J..................... -- 250,001 -- $ -- -- 26,750 7.52% Series K..................... -- 265,000 -- -- -- 28,951 --------- ---------- -------- ----------- ----------- -- 515,001 -- -- 55,701 Redemption Within One Year -- (10,833) --------- ---------- -------- ----------- ----------- Total Subject to Mandatory Redemption ........................ -- 515,001 $ -- -- 44,868 ========= ========== ======== ----------- ----------- SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST OR LIMITED PARTNERSHIP HOLDING SOLELY SUBORDINATED DEBENTURES OF SUBSIDIARIES (NOTE 5F): Ohio Edison Co. Cumulative, $25 stated value- Authorized 4,800,000 shares 9.00%................................ -- 4,800,000 -- $ -- -- 120,000 ========= ========== ======== ----------- ----------- Cleveland Electric Illuminating Co. Cumulative, $25 stated value- Authorized 4,000,000 shares 9.00%................................ 4,000,000 4,000,000 -- $ -- 100,000 100,000 ========= ========== ======== ----------- ----------- Jersey Central Power & Light Co. Cumulative, $25 stated value- Authorized 5,000,000 shares 8.56%................................ 5,000,000 5,000,000 25.00 $125,000 125,244 125,250 ========= ========== ======== ----------- ----------- Metropolitan Edison Co. Cumulative, $25 stated value- Authorized 4,000,000 shares 7.35%................................ 4,000,000 4,000,000 -- $ -- 92,409 92,200 ========= ========== ======== ----------- ----------- Pennsylvania Electric Co. Cumulative, $25 stated value- Authorized 4,000,000 shares 7.34%................................ 4,000,000 4,000,000 -- $ -- 92,214 92,000 ========= ========== ======== ----------- -----------
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd) LONG-TERM DEBT (Note 5G) (Interest rates reflect weighted average rates) (In thousands) - ---------------------------------------------------------------------------------------------------------------------------------- FIRST MORTGAGE BONDS SECURED NOTES UNSECURED NOTES TOTAL - ---------------------------------------------------------------------------------------------------------------------------------- As of December 31, 2002 2001 2002 2001 2002 2001 2002 2001 ---- ---- ---- ---- ---- ---- ---- ---- Ohio Edison Co. - Due 2002-2007 8.02% $ 230,000 $ 509,265 7.66% $ 186,549 $ 231,907 4.17% $ 441,725 $ 441,725 Due 2008-2012 -- -- -- 7.00% 5,468 5,468 -- -- -- Due 2013-2017 -- -- -- 5.09% 59,000 59,000 -- -- -- Due 2018-2022 8.75% 50,960 50,960 7.01% 60,443 60,443 -- -- -- Due 2023-2027 7.76% 168,500 168,500 -- -- -- -- -- -- Due 2028-2032 -- -- -- 3.60% 249,634 249,634 -- -- -- Due 2033-2037 -- -- -- 2.43% 71,900 71,900 -- -- -- ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Total-Ohio Edison 449,460 728,725 632,994 678,352 441,725 441,725 $ 1,524,179 $ 1,848,802 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Cleveland Electric Illuminating Co. - Due 2002-2007 8.97% 400,000 595,000 5.74% 680,175 713,205 5.58% 27,700 27,700 Due 2008-2012 6.86% 125,000 125,000 7.43% 151,610 151,610 -- -- -- Due 2013-2017 -- -- -- 7.88% 300,000 378,700 6.00% 78,700 -- Due 2018-2022 -- -- -- 6.24% 140,560 140,560 -- -- -- Due 2023-2027 9.00% 150,000 150,000 7.64% 218,950 218,950 -- -- -- Due 2028-2032 -- -- -- 5.38% 5,993 5,993 -- -- -- Due 2033-2037 -- -- -- 1.60% 30,000 -- -- -- -- ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Total-Cleveland Electric 675,000 870,000 1,527,288 1,609,018 106,400 27,700 2,308,688 2,506,718 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Toledo Edison Co - Due 2002-2007 7.90% 178,725 179,125 6.19% 229,700 258,700 4.83% 91,100 226,130 Due 2008-2012 -- -- -- -- -- -- 10.00% 760 760 Due 2013-2017 -- -- -- -- -- -- -- -- -- Due 2018-2022 -- -- -- 7.89% 114,000 129,000 -- -- -- Due 2023-2027 -- -- -- 7.31% 60,800 60,800 -- -- -- Due 2028-2032 -- -- -- 5.38% 3,751 3,751 -- -- -- Due 2033-2037 -- -- -- 1.68% 51,100 30,900 -- -- -- ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Total-Toledo Edison 178,725 179,125 459,351 483,151 91,860 226,890 729,936 889,166 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Pennsylvania Power Co.- Due 2002-2007 7.19% 79,370 80,344 2.99% 10,300 10,300 4.39% 19,700 5,200 Due 2008-2012 9.74% 4,870 4,870 -- -- -- -- -- -- Due 2013-2017 9.74% 4,870 4,870 3.12% 29,525 29,525 -- -- -- Due 2018-2022 8.58% 29,231 29,231 3.94% 31,282 31,282 -- -- -- Due 2023-2027 7.63% 6,500 6,500 6.15% 12,700 27,200 -- -- -- Due 2028-2032 -- -- -- 5.79% 23,172 23,172 -- -- -- ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Total-Penn Power 124,841 125,815 106,979 121,479 19,700 5,200 251,520 252,494 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Jersey Central Power & Light Co. - Due 2002-2007 6.90% 442,674 541,260 5.60% 241,135 150,000 7.69% 93 107 Due 2008-2012 7.13% 5,040 5,040 5.39% 52,273 -- 7.69% 134 134 Due 2013-2017 7.10% 12,200 12,200 6.01% 176,592 -- 7.69% 193 193 Due 2018-2022 8.62% 76,586 170,000 -- -- -- 7.69% 280 280 Due 2023-2027 7.37% 365,000 365,000 -- -- -- 7.69% 406 406 Due 2028-2032 -- -- -- -- -- -- 7.69% 588 588 Due 2033-2037 -- -- -- -- -- -- 7.69% 851 851 Due 2038-2042 -- -- -- -- -- -- 7.69% 439 439 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Total-Jersey Central 901,500 1,093,500 470,000 150,000 2,984 2,998 1,374,484 1,246,498 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Metropolitan Edison Co.- Due 2002-2007 6.71% 202,175 262,175 5.79% 150,000 100,000 7.69% 185 214 Due 2008-2012 6.00% 6,525 6,525 -- -- -- 7.69% 267 267 Due 2013-2017 -- -- -- -- -- -- 7.69% 387 387 Due 2018-2022 7.86% 88,500 88,500 -- -- -- 7.69% 560 560 Due 2023-2027 7.55% 133,690 133,690 -- -- -- 7.69% 812 812 Due 2028-2032 -- -- -- -- -- -- 7.69% 1,176 1,176 Due 2033-2037 -- -- -- -- -- -- 7.69% 1,703 1,703 Due 2038-2042 -- -- -- -- -- -- 7.69% 878 878 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Total-Metropolitan Edison 430,890 490,890 150,000 100,000 5,968 5,997 586,858 596,887 ---------- ---------- ---------- ---------- ---------- ---------- ----------- -----------
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd) LONG-TERM DEBT (Interest rates reflect weighted average rates) (Cont'd) (In thousands) - ---------------------------------------------------------------------------------------------------------------------------------- FIRST MORTGAGE BONDS SECURED NOTES UNSECURED NOTES TOTAL - ---------------------------------------------------------------------------------------------------------------------------------- As of December 31, 2002 2001 2002 2001 2002 2001 2002 2001 ---- ---- ---- ---- ---- ---- ---- ---- Pennsylvania Electric Co. - Due 2002-2007 6.13% $ 3,905 $ 4,110 -- $ -- $ -- 5.86% $ 133,093 $ 183,107 Due 2008-2012 5.35% 24,310 24,310 -- -- -- 6.55% 135,134 135,134 Due 2013-2017 -- -- -- -- -- -- 7.69% 193 193 Due 2018-2022 5.80% 20,000 20,000 -- -- -- 6.63% 125,280 125,280 Due 2023-2027 6.05% 25,000 25,000 -- -- -- 7.69% 406 406 Due 2028-2032 -- -- -- -- -- -- 7.69% 588 588 Due 2033-2037 -- -- -- -- -- -- 7.69% 851 851 Due 2038-2042 -- -- -- -- -- -- 7.69% 439 439 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Total-Pennsylvania Electric 73,215 73,420 -- -- 395,984 445,998 $ 469,199 $ 519,418 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- FirstEnergy Corp. - Due 2002-2007 -- -- -- -- -- -- 5.28% 1,695,000 1,550,000 Due 2008-2012 -- -- -- -- -- -- 6.45% 1,500,000 1,500,000 Due 2013-2017 -- -- -- -- -- -- -- -- -- Due 2018-2022 -- -- -- -- -- -- -- -- -- Due 2023-2027 -- -- -- -- -- -- -- -- -- Due 2028-2032 -- -- -- -- -- -- 7.38% 1,500,000 1,500,000 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Total-FirstEnergy -- -- -- -- 4,695,000 4,550,000 4,695,000 4,550,000 --------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- OES Fuel -- -- -- -- 81,515 -- -- -- -- 81,515 AFN Finance Co. No. 1 -- -- -- -- 15,000 -- -- -- -- 15,000 AFN Finance Co. No. 3 -- -- -- -- 4,000 -- -- -- -- 4,000 Bay Shore Power -- -- 6.24% 143,200 145,400 -- -- -- 143,200 145,400 MARBEL Energy Corp. -- -- -- -- -- -- -- 569 -- 569 Facilities Services Group -- -- 4.86% 13,205 15,735 -- -- -- 13,205 15,735 FirstEnergy Generation -- -- -- -- -- 5.00% 15,000 -- 15,000 -- FirstEnergy Properties -- -- 7.89% 9,679 9,902 -- -- -- 9,679 9,902 Warrenton River Terminal -- -- 5.25% 634 776 -- -- -- 634 776 GPU Capital* -- -- -- -- -- 5.78% 101,467 1,629,582 101,467 1,629,582 GPU Power -- -- 7.14% 174,760 239,373 11.87% 67,372 56,048 242,132 295,421 ---------- ---------- ---------- ---------- ---------- ---------- ----------- ----------- Total $2,833,631 $3,561,475 $3,688,090 $3,653,701 $5,943,460 $7,392,707 12,465,181 14,607,883 ========== ========== ========== ========== ========== ========== ----------- ----------- Capital lease obligations............................................................................. 15,761 19,390 Net unamortized premium on debt*...................................................................... 92,346 213,834 Long-term debt due within one year*................................................................... (1,701,072) (1,975,755) ----------- ----------- Total long-term debt*................................................................................. 10,872,216 12,865,352 ----------- ----------- TOTAL CAPITALIZATION* $18,755,776 $21,339,001 - ---------------------------------------------------------------------------------------------------------------------------------- * 2001 includes amounts in "Liabilities Related to Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2001. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY Accumulated Unallocated Other Other ESOP Comprehensive Number Par Paid-In Comprehensive Retained Common Income of Shares Value Capital Income (Loss) Earnings Stock ------------- --------- ----- ------- ------------- -------- ----------- (Dollars in thousands) Balance, January 1, 2000 ............... 232,454,287 $23,245 $3,722,375 $ (195) $ 945,241 $(126,776) Net income............................ $598,970 598,970 Minimum liability for unfunded retirement benefits, net of $85,000 of income taxes............. (134) (134) Unrealized gain on investment in securities available for sale ...... 922 922 -------- Comprehensive income.................. $599,758 ======== Reacquired common stock............... (7,922,707) (792) (194,210) Allocation of ESOP shares............. 3,656 15,044 Cash dividends on common stock........ (334,220) - --------------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000.............. 224,531,580 22,453 3,531,821 593 1,209,991 (111,732) GPU acquisition....................... 73,654,696 7,366 2,586,097 Net income............................ $646,447 646,447 Minimum liability for unfunded retirement benefits, net of $(182,000) of income taxes.......... (268) (268) Unrealized loss on derivative hedges, net of $(116,521,000) of income taxes ....................... (169,408) (169,408) Unrealized gain on investments, net of $56,000 of income taxes...... 81 81 Unrealized currency translation adjustments, net of $(1,000) of income taxes .................... (1) (1) -------- Comprehensive income.................. $476,851 ======== Reacquired common stock............... (550,000) (55) (15,253) Allocation of ESOP shares............. 10,595 14,505 Cash dividends on common stock........ (334,633) - --------------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001.............. 297,636,276 29,764 6,113,260 (169,003) 1,521,805 (97,227) Net income............................ $629,280 629,280 Minimum liability for unfunded retirement benefits, net of $(316,681,000) of income taxes...... (449,615) (449,615) Unrealized gain on derivative hedges, net of $37,458,000 of income taxes. ................... 59,187 59,187 Unrealized loss on investments, net of $(8,721,000) of income taxes... ........................... (12,357) (12,357) Unrealized currency translation adjustments......................... (91,448) (91,448) -------- Comprehensive income.................. $135,047 ======== Stock options exercised............... (8,169) Allocation of ESOP shares............. 15,250 18,950 Cash dividends on common stock........ (439,628) - --------------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002.............. 297,636,276 $29,764 $6,120,341 $(663,236) $1,711,457 $ (78,277) ================================================================================================================================= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemption -------------------- -------------------- Par or Par or Number Stated Number Stated of Shares Value of Shares Value --------- ------ --------- ------ (Dollars in thousands) Balance, January 1, 2000 12,324,699 $648,395 5,269,680 $294,710 Redemptions- 8.45% Series (50,000) (5,000) $ 7.35 Series C (10,000) (1,000) $88.00 Series E (3,000) (3,000) $91.50 Series Q (10,714) (10,714) $90.00 Series S (18,750) (18,750) Amortization of fair market value adjustments- $ 7.35 Series C (69) $88.00 Series R (3,872) $90.00 Series S (5,734) ----------------------------------------------------------------------------------- Balance, December 31, 2000 12,324,699 648,395 5,177,216 246,571 GPU acquisition 125,000 12,649 13,515,001 365,151 Issues- 9.00% Series 4,000,000 100,000 Redemptions- 8.45% Series (50,000) (5,000) $ 7.35 Series C (10,000) (1,000) $88.00 Series R (50,000) (50,000) $91.50 Series Q (10,716) (10,716) $90.00 Series S (18,750) (18,750) Amortization of fair market value adjustments- $ 7.35 Series C (11) $88.00 Series R (1,128) $90.00 Series S (668) ----------------------------------------------------------------------------------- Balance, December 31, 2001 12,449,699 661,044 22,552,751 624,449 Redemptions- 7.75% Series (4,000,000) (100,000) $7.56 Series B (450,000) (45,071) $42.40 Series T (200,000) (96,850) $8.32 Series (100,000) (10,000) $7.76 Series (150,000) (15,000) $7.80 Series (150,000) (15,000) $10.00 Series (190,000) (19,000) $2.21 Series (1,000,000) (25,000) 7.625% Series (7,500) (750) $7.35 Series C (10,000) (1,000) $90.00 Series S (17,750) (17,010) 8.65% Series J (250,001) (26,750) 7.52% Series K (265,000) (28,951) 9.00% Series (4,800,000) (120,000) Amortization of fair market value adjustments- $ 7.35 Series C (9) $90.00 Series S (258) 8.56% Series (6) 7.35% Series 209 7.34% Series 214 ----------------------------------------------------------------------------------- Balance, December 31, 2002 6,209,699 $335,123 17,202,500 $430,138 =================================================================================== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 - --------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income..................................................... $ 629,280 $ 646,447 $ 598,970 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization................ 1,105,904 889,550 933,684 Nuclear fuel and lease amortization........................ 80,507 98,178 113,330 Other amortization, net (Note 2)........................... (16,593) (11,927) (11,635) Deferred costs recoverable as regulatory assets............ (362,956) (31,893) -- Avon investment impairment (Note 3)........................ 50,000 -- -- Deferred income taxes, net................................. 91,032 31,625 (79,429) Investment tax credits, net................................ (27,071) (22,545) (30,732) Cumulative effect of accounting change..................... 43,521 14,338 -- Receivables................................................ (78,378) 53,099 (150,520) Materials and supplies..................................... (29,557) (50,052) (29,653) Accounts payable........................................... 214,084 (84,572) 118,282 Other (Note 9)............................................. 215,514 (250,564) 45,529 ----------- ---------- ---------- Net cash provided from operating activities.............. 1,915,287 1,281,684 1,507,826 ----------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Preferred stock.............................................. -- 96,739 -- Long-term debt............................................... 668,676 4,338,080 307,512 Short-term borrowings, net................................... 478,520 -- 281,946 Redemptions and Repayments- Common stock................................................. -- (15,308) (195,002) Preferred stock.............................................. (522,223) (85,466) (38,464) Long-term debt............................................... (1,308,814) (394,017) (901,764) Short-term borrowings, net................................... -- (1,641,484) -- Common Stock Dividend Payments................................. (439,628) (334,633) (334,220) ----------- ---------- ---------- Net cash provided from (used for) financing activities... (1,123,469) 1,963,911 (879,992) ----------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: GPU acquisition, net of cash................................... -- (2,013,218) -- Property additions............................................. (997,723) (852,449) (587,618) Proceeds from sale of Midlands................................. 155,034 -- -- Avon cash and cash equivalents (Note 3)........................ 31,326 -- -- Net assets held for sale....................................... (31,326) -- -- Cash investments (Note 2)...................................... 81,349 24,518 17,449 Other (Note 9)................................................. (54,355) (233,526) (120,195) ----------- ---------- ---------- Net cash provided from (used for) investing activities... (815,695) (3,074,675) (690,364) ----------- ---------- ---------- Net increase (decrease) in cash and cash equivalents........... (23,877) 170,920 (62,530) Cash and cash equivalents at beginning of year................. 220,178 49,258 111,788 ------------ ---------- ---------- Cash and cash equivalents at end of year*...................... $ 196,301 $ 220,178 $ 49,258 =========== ========== ========== SUPPLEMENTAL CASH FLOWS INFORMATION: Cash Paid During the Year- Interest (net of amounts capitalized)........................ $ 881,515 $ 425,737 $ 485,374 Income taxes................................................. $ 389,180 $ 433,640 $ 512,182 * 2001 excludes amounts in "Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2001. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF TAXES For the Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: Real and personal property........................................... $ 218,683 $ 176,916 $ 281,374 State gross receipts*................................................ 132,622 102,335 221,385 Kilowatt-hour excise*................................................ 219,970 117,979 -- Social security and unemployment..................................... 46,345 44,480 39,134 Other................................................................ 32,709 13,630 5,788 ---------- ---------- ---------- Total general taxes........................................... $ 650,329 $ 455,340 $ 547,681 ========== ========== ========== PROVISION FOR INCOME TAXES: Currently payable- Federal........................................................... $ 332,253 $ 375,108 $ 467,045 State............................................................. 103,886 84,322 19,918 Foreign........................................................... 20,624 108 -- ---------- ---------- ---------- 456,763 459,538 486,963 ---------- ---------- ---------- Deferred, net- Federal........................................................... 99,297 37,888 (60,831) State............................................................. 20,487 (6,177) (18,598) Foreign........................................................... 13,600 (86) -- ---------- ---------- ---------- 133,384 31,625 (79,429) ---------- ---------- ---------- Investment tax credit amortization................................... (27,071) (22,545) (30,732) ---------- ---------- ---------- Total provision for income taxes.............................. $ 563,076 $ 468,618 $ 376,802 ========== ========== ========== RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes........................ $1,192,356 $1,115,065 $ 975,772 ========== ========== ========== Federal income tax expense at statutory rate......................... $ 417,325 $ 390,273 $ 341,520 Increases (reductions) in taxes resulting from- Amortization of investment tax credits............................ (27,071) (22,545) (30,732) State income taxes, net of federal income tax benefit............. 80,842 50,794 1,133 Amortization of tax regulatory assets............................. 27,455 30,419 38,702 Amortization of goodwill.......................................... -- 18,416 18,420 Preferred stock dividends......................................... 13,634 19,733 18,172 Valuation reserve for foreign tax benefits........................ 31,087 -- -- Other, net........................................................ 19,804 (18,472) (10,413) ---------- ---------- ---------- Total provision for income taxes.............................. $ 563,076 $ 468,618 $ 376,802 ========== ========== ========== ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences........................................... $2,052,594 $1,996,937 $1,245,297 Customer receivables for future income taxes......................... 144,073 178,683 62,527 Competitive transition charge........................................ 1,234,491 1,289,438 1,070,161 Deferred sale and leaseback costs.................................... (99,647) (77,099) (128,298) Nonutility generation costs.......................................... (228,476) (178,393) -- Unamortized investment tax credits................................... (78,227) (86,256) (85,641) Unused alternative minimum tax credits............................... -- -- (32,215) Other comprehensive income........................................... (240,663) (115,395) -- Other (Notes 2 and 9)................................................ (416,148) (323,696) (37,724) ---------- ---------- ---------- Net deferred income tax liability**........................... $2,367,997 $2,684,219 $2,094,107 ========== ========== ========== * Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income. ** 2001 excludes amounts in "Liabilities Related to Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2001. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. GENERAL: The consolidated financial statements include FirstEnergy Corp., a public utility holding company, and 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, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). ATSI owns and operates FirstEnergy's transmission facilities within the service areas of OE, CEI and TE (Ohio Companies) and Penn. The utility subsidiaries are referred to throughout as "Companies." FirstEnergy's 2001 results include the results of JCP&L, Met-Ed and Penelec from the period they were acquired on November 7, 2001 through December 31, 2001. The consolidated financial statements also include FirstEnergy's other principal subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FSG); MYR Group, Inc.; MARBEL Energy Corporation; FirstEnergy Nuclear Operating Company (FENOC); GPU Capital, Inc.; GPU Power, Inc.; FirstEnergy Service Company (FECO); and GPU Service, Inc. (GPUS). FES provides energy-related products and services and, through its FirstEnergy Generation Corp. (FGCO) subsidiary, operates FirstEnergy's nonnuclear generation business. FENOC operates the Companies' nuclear generating facilities. FSG is the parent company of several heating, ventilating, air conditioning and energy management companies, and MYR is a utility infrastructure construction service company. MARBEL is a fully integrated natural gas company. 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. Significant intercompany transactions have been eliminated in consolidation. The Companies follow the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC), the New Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Certain prior year amounts have been reclassified to conform with the current year presentation, as described further in Notes 8 and 9. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (A) CONSOLIDATION- FirstEnergy consolidates all majority-owned subsidiaries, after eliminating the effects of intercompany transactions. Non-majority owned investments, including investments in limited liability companies, partnerships and joint ventures, are accounted for under the equity method when FirstEnergy is able to influence their financial or operating policies. Investments in corporations resulting in voting control of 20% or more are presumed to be equity method investments. Limited partnerships are evaluated in accordance with SEC Staff D-46, "Accounting for Limited Partnership Investments" and American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence. For all remaining investments (excluding those within the scope of Statement of Financial Accounting Standards (SFAS) 115, FirstEnergy applies the cost method. (B) EARNINGS PER SHARE- Basic earnings per share are computed using the weighted average of actual common shares outstanding as the denominator. Diluted earnings per share reflect the weighted average of actual common shares outstanding plus the potential additional common shares that could result if dilutive securities and agreements were exercised in the denominator. In 2002, 2001 and 2000, stock based awards to purchase shares of common stock totaling 3.4 million, 0.1 million and 1.8 million, respectively, were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. The numerators for the calculations of basic and diluted earnings per share are Income Before Cumulative Effect of Changes in Accounting and Net Income. The following table reconciles the denominators for basic and diluted earnings per share: Denominator for Earnings per Share Calculations ----------------------------------------------- Years Ended December 31, ------------------------------------------------------------------------------- 2002 2001 2000 ------------------------------------------------------------------------------ (In thousands) Denominator for basic earnings per share (weighted average shares actually outstanding) 293,194 229,512 222,444 Assumed exercise of dilutive securities or agreements to issue common stock 1,227 918 282 ------------------------------------------------------------------------------ Denominator for diluted earnings per share 294,421 230,430 222,726 ============================================================================== (C) REVENUES- The Companies' principal business is providing electric service to customers in Ohio, Pennsylvania and New Jersey. The Companies' retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service provided through the end of the year. See Note 9 - Other Information for discussion of reporting of independent system operator (ISO) transactions. Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2002 or 2001, with respect to any particular segment of FirstEnergy's customers. CEI and TE sell substantially all of their retail customers' receivables to Centerior Funding Corporation (CFC), a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (an SFAS 140 "qualified special purpose entity") under an asset-backed securitization agreement. Transfers are made in return for an interest in the trust (41% as of December 31, 2002), which is stated at fair value, reflecting adjustments for anticipated credit losses. The average collection period for billed receivables is 28 days. Given the short collection period after billing, the fair value of CFC's interest in the trust approximates the stated value of its retained interest in underlying receivables after adjusting for anticipated credit losses. Accordingly, subsequent measurements of the retained interest under SFAS 115 (as an available-for-sale financial instrument) result in no material change in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated credit losses would not have significantly affected FirstEnergy's retained interest in the pool of receivables through the trust. Of the $272 million sold to the trust and outstanding as of December 31, 2002, FirstEnergy's retained interests in $111 million of the receivables are included as other receivables on the Consolidated Balance Sheets. Accordingly, receivables recorded on the Consolidated Balance Sheets were reduced by approximately $161 million due to these sales. Collections of receivables previously transferred to the trust and used for the purchase of new receivables from CFC during 2002 totaled approximately $2.2 billion. CEI and TE processed receivables for the trust and received servicing fees of approximately $3.8 million in 2002. Expenses associated with the factoring discount related to the sale of receivables were $4.7 million in 2002. In June 2002, the Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Based on the EITF's partial consensus position, for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour (KWH) sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. FirstEnergy has previously reported such contracts as gross revenues and purchased power costs. Comparative quarterly disclosures and the Consolidated Statements of Income for revenues and expenses have been reclassified for 2002 only to conform with the revised presentation (see Note 11 - Summary of Quarterly Financial Data). In addition, the related KWH sales and purchases statistics described under Management's Discussion and Analysis - Results of Operations were reclassified (7.2 billion KWH in 2002 and 3.7 billion KWH in 2001). The following table displays the impact of changing to a net presentation for FirstEnergy's energy trading operations. 2002 Impact of Recording Energy Trading Net Revenues Expenses - ------------------------------------------------------------------------ (in millions) Total before adjustment $12,420 $10,238 Adjustment (268) (268) - ------------------------------------------------------------------------ Total as reported $12,152 $ 9,970 ======================================================================== (D) REGULATORY MATTERS- In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included 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 (or transition costs); o itemizing (unbundling) the 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. Ohio In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. In July 2000, the PUCO approved FirstEnergy's transition plan for the 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. New Jersey 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 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 (see Note 5). 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. The Administrative Law Judge's recommended decision is due in June 2003 and the NJBPU's subsequent decision is due in July 2003. 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 cost balances. Pennsylvania 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. 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 of $55.8 million ($32.6 million net of tax) to income 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 CTC recovery of PLR costs above Met-Ed's and Penelec's capped generation rates 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. The application of SFAS 71 has been discontinued with respect to the Companies' generation operations. The SEC issued interpretive guidance regarding asset impairment measurement, concluding that any supplemental regulated cash flows such as a CTC should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance, $1.8 billion of impaired plant investments ($1.2 billion, $227 million, $304 million and $53 million for OE, Penn, CEI and TE, respectively) were recognized as regulatory assets recoverable as transition costs through future regulatory cash flows. The following summarizes net assets included in property, plant and equipment relating to operations for which the application of SFAS 71 was discontinued, compared with the respective company's total assets as of December 31, 2002. SFAS 71 Discontinued Net Assets Total Assets -------------------------------------------- (In millions) OE $ 947 $7,160 CEI 1,406 5,935 TE 559 2,617 Penn 82 908 JCP&L 44 8,053 Met-Ed 17 3,565 Penelec -- 3,163 -------------------------------------------- (E) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (except for nuclear generating units and the international properties which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs. JCP&L holds a 50% ownership interest in Yards Creek Pumped Storage Facility - its net book value was approximately $21.3 million as of December 31, 2002. FirstEnergy also shares ownership interests in various foreign properties with an aggregate net book value of $154 million, representing the fair value of FirstEnergy's interest. FirstEnergy's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for the Companies' electric plant in 2002, 2001 and 2000 (post merger periods only for JCP&L, Met-Ed and Penelec) are shown in the following table: Annual Composite Depreciation Rate ------------------------------------------------ 2002 2001 2000 ------------------------------------------------ OE 2.7% 2.7% 2.8% CEI 3.4 3.2 3.4 TE 3.9 3.5 3.4 Penn 2.9 2.9 2.6 JCP&L 3.5 3.4 Met-Ed 3.0 3.0 Penelec 3.0 2.9 ------------------------------------------------- Annual depreciation expense in 2002 included approximately $125 million for future decommissioning costs applicable to the Companies' ownership and leasehold interests in five nuclear generating units (Davis-Besse Unit 1, Beaver Valley Units 1 and 2, Perry Unit 1 and Three Mile Island Unit 2 (TMI-2)), a demonstration nuclear reactor (Saxton Nuclear Experimental Facility) owned by a wholly-owned subsidiary of JCP&L, Met-Ed and Penelec, and decommissioning liabilities for previously divested GPU nuclear generating units. The Companies' share of the future obligation to decommission these units is approximately $2.6 billion in current dollars and (using a 4.0% escalation rate) approximately $5.3 billion in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Decommissioning of the demonstration nuclear reactor is expected to be completed in 2003; payments for decommissioning of the nuclear generating units are expected to begin in 2014, when actual decommissioning work is expected to begin. The Companies have recovered approximately $671 million for decommissioning through their electric rates from customers through December 31, 2002. The Companies have also recognized an estimated liability of approximately $37 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy, as required by the Energy Policy Act of 1992. In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. FirstEnergy has identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143, asset retirement costs of $807 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $437 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets". No impairment was indicated. The asset retirement liability at the date of adoption will be $1.109 billion. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.232 billion, including unrealized gains on decommissioning trust funds of $12 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that the ultimate nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn will be tracked and recovered through their regulated rates. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning for those companies. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $298 million increase to income ($174 million net of tax). The $12 million of unrealized gains ($7 million net of tax) included in the decommissioning liability balances as of December 31, 2002, was offset against other comprehensive income (OCI) upon adoption of SFAS 143. The FASB approved SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using purchase accounting. The provisions of the new standard relating to the determination of goodwill and other intangible assets have been applied to the GPU merger, which was accounted for as a purchase transaction, and have not materially affected the accounting for this transaction. Under SFAS 142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill is tested for impairment at least on an annual basis - based on the results of the transition analysis and the 2002 annual analysis, no impairment of FirstEnergy's goodwill is required. The impairment analysis includes a significant source of cash representing EUOC recovery of transition costs as described above under "Regulatory Matters." FirstEnergy does not believe that completion of transition cost recovery will result in an impairment of goodwill relating to its regulated business segment. Prior to the adoption of SFAS 142, FirstEnergy amortized about $57 million ($.23 per share of common stock) of goodwill annually. There was no goodwill amortization in 2001 associated with the GPU merger under the provisions of the new standard. The following table displays what net income and earnings per share would have been if goodwill amortization had been excluded in 2001 and 2000: 2002 2001 2000 ---- ---- ---- (In thousands, except per share amounts) Reported net income.................. $629,280 $646,447 $598,970 Goodwill amortization (net of tax)... -- 54,584 54,138 -------- -------- -------- Adjusted net income.................. $629,280 $701,031 $653,108 ======== ======== ======== Basic earnings per common share: Reported earnings per share....... $2.15 $2.82 $2.69 Goodwill amortization............. -- 0.23 0.25 ----- ----- ----- Adjusted earnings per share....... $2.15 $3.05 $2.94 ===== ===== ===== Diluted earnings per common share: Reported earnings per share....... $2.14 $2.81 $2.69 Goodwill amortization............. -- 0.23 0.24 ----- ----- ----- Adjusted earnings per share....... $2.14 $3.04 $2.93 ===== ===== ===== The net change of $295 million in the goodwill balance as of December 31, 2002 compared to the December 31, 2001 balance primarily reflects the $135.3 million after-tax effect of the Pennsylvania PLR reserve discussed in Note 2D - Regulatory Matters - Pennsylvania and finalization of the initial purchase price allocation for the GPU acquisition (see Note 12). (F) NUCLEAR FUEL- Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Companies amortize the cost of nuclear fuel based on the rate of consumption. (G) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 5C). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date, resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows: 2002 2001 2000 - ----------------------------------------------------------------------------- Valuation assumptions: Expected option term (years) 8.1 8.3 7.6 Expected volatility 23.31% 23.45% 21.77% Expected dividend yield 4.36% 5.00% 6.68% Risk-free interest rate 4.60% 4.67% 5.28% Fair value per option $6.45 $4.97 $2.86 ---------------------------------------------------------------------------- The effects of applying fair value accounting to the FirstEnergy's stock options would be to reduce net income and earnings per share. The following table summarizes this effect. 2002 2001 2000 -------------------------------------------------------------------------- (In thousands) Net Income, as reported $629,280 $646,447 $598,970 Add back compensation expense reported in net income, net of tax (based on APB 25) 166 25 144 Deduct compensation expense based upon fair value, net of tax (8,825) (3,748) (1,736) -------------------------------------------------------------------------- Adjusted net income $620,621 $642,724 $597,378 -------------------------------------------------------------------------- Earnings Per Share of Common Stock - Basic As Reported $2.15 $2.82 $2.69 Adjusted $2.11 $2.80 $2.69 Diluted As Reported $2.14 $2.81 $2.69 Adjusted $2.11 $2.79 $2.69 (H) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Valuation allowances of $465 million were established and included in the Consolidated Balance Sheet as of December 31, 2002, primarily associated with certain fair value adjustments (see Note 12) and capital losses related to the divestitures of international assets owned by the former GPU, Inc. prior to its acquisition by FirstEnergy. Of the total valuation allowance, $325 million relates to capital loss carryforwards that expire at the end of 2007. Management is unable to predict whether sufficient capital gains will be generated to utilize all of these capital loss carryforwards. Any ultimate utilization of these capital loss carryforwards for which valuation allowances have been established would reduce goodwill. (I) RETIREMENT BENEFITS- FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. On December 31, 2001, the GPU pension plans were merged with the FirstEnergy plan. FirstEnergy uses the projected unit credit method for funding purposes and was not required to make pension contributions during the three years ended December 31, 2002. The assets of the pension plan consist primarily of common stocks, United States government bonds and corporate bonds. Costs for the year 2001 include the former GPU companies' pension and other postretirement benefit costs for the period November 7, 2001 through December 31, 2001. FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. FirstEnergy pays insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by FirstEnergy. FirstEnergy recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. As a result of the reduced market value of FirstEnergy's pension plan assets, it was required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. FirstEnergy's accumulated benefit obligation of $3.438 billion exceeded the fair value of plan assets ($2.889 billion) resulting in a minimum pension liability of $548.6 million. FirstEnergy eliminated its prepaid pension asset of $286.9 million and established a minimum liability of $548.6 million, recording an intangible asset of $78.5 million and reducing OCI by $444.2 million (recording a related deferred tax asset of $312.8 million). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002, increased due to the lower discount rate and asset returns assumed as of December 31, 2002. The following sets forth the funded status of the plans and amounts recognized on the Consolidated Balance Sheets as of December 31:
Other Pension Benefits Postretirement Benefits ---------------- ----------------------- 2002 2001 2002 2001 --------------------------------------------------------------------------------------------- (In millions) Change in benefit obligation: Benefit obligation as of January 1 $3,547.9 $1,506.1 $ 1,581.6 $ 752.0 Service cost 58.8 34.9 28.5 18.3 Interest cost 249.3 133.3 113.6 64.4 Plan amendments -- 3.6 (121.1) -- Actuarial loss 268.0 123.1 440.4 73.3 Voluntary early retirement program -- -- -- 2.3 GPU acquisition (Note 12) (11.8) 1,878.3 110.0 716.9 Benefits paid (245.8) (131.4) (83.0) (45.6) ------------------------------------------------------------------------------------------- Benefit obligation as of December 31 3,866.4 3,547.9 2,070.0 1,581.6 ------------------------------------------------------------------------------------------- Change in fair value of plan assets: Fair value of plan assets as of January 1 3,483.7 1,706.0 535.0 23.0 Actual return on plan assets (348.9) 8.1 (57.1) 12.7 Company contribution -- -- 37.9 43.3 GPU acquisition -- 1,901.0 -- 462.0 Benefits paid (245.8) (131.4) (42.5) (6.0) ------------------------------------------------------------------------------------------- Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0 ------------------------------------------------------------------------------------------- Funded status of plan (977.4) (64.2) (1,596.7) (1,046.6) Unrecognized actuarial loss 1,185.8 222.8 751.6 212.8 Unrecognized prior service cost 78.5 87.9 (106.8) 17.7 Unrecognized net transition obligation -- -- 92.4 101.6 ------------------------------------------------------------------------------------------- Net amount recognized $ 286.9 $ 246.5 $ (859.5) $ (714.5) =========================================================================================== Consolidated Balance Sheets classification: Prepaid (accrued) benefit cost $ (548.6) $ 246.5 $ (859.5) $ (714.5) Intangible asset 78.5 -- -- -- Accumulated other comprehensive loss 757.0 -- -- -- ------------------------------------------------------------------------------------------- Net amount recognized $ 286.9 $ 246.5 $ (859.5) $ (714.5) ============================================================================================ Assumptions used as of December 31: Discount rate 6.75% 7.25% 6.75% 7.25% Expected long-term return on plan assets 9.00% 10.25% 9.00% 10.25% Rate of compensation increase 3.50% 4.00% 3.50% 4.00%
Net pension and other postretirement benefit costs for the three years ended December 31, 2002 were computed as follows:
Other Pension Benefits Postretirement Benefits ------------------------ -------------------------- 2002 2001 2000 2002 2001 2000 ----------------------------------------------------------------------------------------------------------- (In millions) Service cost $ 58.8 $ 34.9 $ 27.4 $ 28.5 $18.3 $11.3 Interest cost 249.3 133.3 104.8 113.6 64.4 45.7 Expected return on plan assets (346.1) (204.8) (181.0) (51.7) (9.9) (0.5) Amortization of transition obligation (asset) -- (2.1) (7.9) 9.2 9.2 9.2 Amortization of prior service cost 9.3 8.8 5.7 3.2 3.2 3.2 Recognized net actuarial loss (gain) -- -- (9.1) 11.2 4.9 -- Voluntary early retirement program -- 6.1 17.2 -- 2.3 -- ----------------------------------------------------------------------------------------------------------- Net periodic benefit cost (income) $ (28.7) $ (23.8) $ (42.9) $114.0 $92.4 $68.9 ===========================================================================================================
The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. (J) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. As of December 31, 2002, cash and cash equivalents included $50 million used for the redemption of long-term debt in January 2003. Noncash financing and investing activities included the 2001 FirstEnergy common stock issuance of $2.6 billion for the GPU acquisition and capital lease transactions amounting to $3.1 million and $89.3 million for the years 2001 and 2000, respectively. There were no capital lease transactions in 2002. Commercial paper transactions of OES Fuel, Incorporated (a wholly owned subsidiary of OE) that had initial maturity periods of three months or less were reported net within financing activities under long-term debt, prior to the expiration of the related long-term financing agreement in March 2002, and were reflected as currently payable long-term debt on the Consolidated Balance Sheet as of December 31, 2001. Net losses on foreign currency exchange transactions reflected in FirstEnergy's 2002 Consolidated Statement of Income consisted of approximately $104.1 million from FirstEnergy's Argentina operations (see Note 3 - Divestitures). In the Consolidated Statements of Cash Flows, the amounts included in "Cash investments" under Net cash used for Investing Activities primarily consist of changes in capital trust investments of $(87) million (see Note 4 - Leases) and other cash investments of $6 million. The amounts included in "Other amortization, net" under Net cash provided from Operating Activities primarily consist of amounts from the reduction of an electric service obligation under a CEI electric service prepayment program. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31:
2002 2001 --------------------------------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value --------------------------------------------------------------------------------------------- (In millions) Long-term debt* $12,465 $12,761 $12,897 $13,097 Preferred stock $ 445 $ 454 $ 636 $ 626 Investments other than cash and cash equivalents: Debt securities: -Maturity (5-10 years) $ 502 $ 471 $ 439 $ 402 -Maturity (more than 10 years) 927 1,030 990 1,009 Equity securities 15 15 15 15 All other 1,668 1,669 1,730 1,734 --------------------------------------------------------------------------------------------- $ 3,112 $ 3,185 $ 3,174 $ 3,160 ============================================================================================ * Excluding approximately $1.75 billion of long-term debt in 2001 related to pending divestitures.
The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to the Companies' ratings. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. The Companies have no securities held for trading purposes. See Note 9 - Other Information for discussion of SFAS 115 activity related to equity investments. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "All other" in the table above) consist of equity securities, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. In conjunction with the adoption of SFAS 143 on January 1, 2003, unrealized gains or losses were reclassified to OCI in accordance with SFAS 115. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized gains (losses) were approximately $(15.6) million and interest and dividend income totaled approximately $33.2 million. On January 1, 2001, FirstEnergy adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an amendment of FASB Statement No. 133". The cumulative effect to January 1, 2001 was a charge of $8.5 million (net of $5.8 million of income taxes) or $.03 per share of common stock. The reported results of operations for the year ended December 31, 2000 would not have been materially different if this accounting had been in effect during that year. FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including electricity, natural gas and coal. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. FirstEnergy uses derivatives to hedge the risk of price and interest rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The maximum periods over which the variability of electricity and natural gas cash flows are hedged are two and three years, respectively. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. Also, gains and losses are included in net income when ineffectiveness occurs on certain natural gas hedges. The impact of ineffectiveness on earnings during 2002 was not material. FirstEnergy entered into interest rate derivative transactions during 2001 to hedge a portion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from hedges of anticipated interest payments on acquisition debt will be included in net income over the periods that hedged interest payments are made - 5, 10 and 30 years. Gains and losses from derivative contracts are included in other operating expenses. The current net deferred loss of $110.2 million included in Accumulated Other Comprehensive Loss (AOCL) as of December 31, 2002, for derivative hedging activity, as compared to the December 31, 2001 balance of $169.4 million in net deferred losses, resulted from the reversal of $6.0 million of derivative losses related to the sale of Avon, a $33.0 million reduction related to current hedging activity and a $20.2 million reduction due to net hedge gains included in earnings during the year. Approximately $19.0 million (after tax) of the current net deferred loss on derivative instruments in AOCL is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. However, the fair value of these derivative instruments will fluctuate from period to period based on various market factors and will generally be more than offset by the margin on related sales and revenues. FirstEnergy also entered into fixed-to-floating interest rate swap agreements during 2002 to increase the variable-rate component of its debt portfolio from 16% to approximately 20% at year end. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues-protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options and interest payment dates match those of the underlying obligations resulting in no ineffectiveness in these hedge positions. After reaching a maximum notional position of $993.5 million in the third quarter of 2002, FirstEnergy unwound $400 million of these swaps in the fourth quarter of 2002 during a period of steadily declining market interest rates. Gains recognized from unwinding these swaps were added to the carrying value of the hedged debt and will be recognized over the remaining life of the underlying debt (through November 2006). FirstEnergy engages in the trading of commodity derivatives and periodically experiences net open positions. FirstEnergy's risk management policies limit the exposure to market risk from open positions and require daily reporting to management of potential financial exposures. (K) REGULATORY ASSETS- The Companies recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations. OE and Penn recognized additional cost recovery of $270 million in 2000 as additional regulatory asset amortization in accordance with their prior Ohio and current Pennsylvania regulatory plans. The Ohio Companies and Penn recognized incremental transition cost recovery aggregating $323 million in 2002 and $309 million in 2001, in accordance with the current Ohio transition plan and Pennsylvania regulatory plan. Regulatory assets which do not earn a current return totaled approximately $475.2 million as of December 31, 2002. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2002 2001 - ------------------------------------------------------------------------------ (In millions) Regulatory transition charge $7,365.3 $7,751.5 Customer receivables for future income taxes 394.0 433.0 Societal benefits charge 143.8 166.6 Loss on reacquired debt 73.7 80.0 Employee postretirement benefit costs 87.7 98.6 Nuclear decommissioning, decontamination and spent fuel disposal costs 98.8 80.2 Provider of last resort costs -- 116.2 Property losses and unrecovered plant costs 87.8 104.1 Other 71.9 82.4 - ----------------------------------------------------------------------------- Total $8,323.0 $8,912.6 - ----------------------------------------------------------------------------- 3. DIVESTITURES: INTERNATIONAL OPERATIONS- FirstEnergy identified certain former GPU international operations for divestiture within one year of the merger. These operations constitute individual "lines of business" as defined in APB 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 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 a 50 percent 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 until February 6, 2002, the date when Aquila began discussions to revise its initial offer to purchase Avon. However, the revision to the initial offer by Aquila caused a reversal of this accounting in the first quarter of 2002, resulting in the recognition of a cumulative effect of a change in accounting which increased net income by $31.7 million. This resulted from the application of guidance provided by 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," and accounting under EITF Issue No. 87-11, recognizing the net income of Avon from November 7, 2001 to February 6, 2002 that previously was not recognized by FirstEnergy in its consolidated earnings as discussed above. 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 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. As a result, under EITF Issue No. 90-6, FirstEnergy recorded in the fourth quarter a one-time, non-cash "Cumulative Effect of Accounting Change" on its 2002 Consolidated Statement of Income related to Emdersa's cumulative results of operations from November 7, 2001 through October 31, 2002. The amount of this one-time, after-tax charge was $88.8 million, or $0.30 per share of common stock (comprised of $104.1 million in currency transaction losses arising principally from U.S. dollar denominated debt, offset by $15.3 million of operating income). On November 1, 2002, FirstEnergy began consolidating the results of Emdersa's operations in its financial statements. In addition to the currency transaction losses of $104.1 million, FirstEnergy recognized a currency translation adjustment in other comprehensive income 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 GAAP financial reporting. SALE OF GENERATING ASSETS- In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 MW to NRG Energy Inc. 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 decided to retain ownership of these plants after reviewing other bids it subsequently received from other parties who had expressed interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, it reflected approximately $74 million ($43 million net of tax) of previously unrecognized depreciation and other transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statement of Income. 4. LEASES: The Companies lease certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE continue to be responsible, to the extent of their individual combined ownership and leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes. OES Finance, Incorporated, a wholly owned subsidiary of OE, maintains deposits pledged as collateral to secure reimbursement obligations relating to certain letters of credit supporting OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits of approximately $278 million pledged to the financial institution providing those letters of credit are the sole property of OES Finance and are investments which are classified as "Held to Maturity". In the event of liquidation, OES Finance, as a separate corporate entity, would have to satisfy its obligations to creditors before any of its assets could be made available to OE as sole owner of OES Finance common stock. Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2002, are summarized as follows: 2002 2001 2000 - ----------------------------------------------------------------------- (In millions) Operating leases Interest element $188.4 $194.1 $202.4 Other 135.9 120.5 111.1 Capital leases Interest element 2.4 8.0 12.3 Other 2.5 35.5 64.2 - ----------------------------------------------------------------------- Total rentals $329.2 $358.1 $390.0 ======================================================================= The future minimum lease payments as of December 31, 2002, are: Operating Leases --------------------------------- Capital Lease Capital Leases Payments Trusts Net - -------------------------------------------------------------------------------- (In millions) 2003 $ 4.6 $ 331.9 $ 178.8 $ 153.1 2004 6.0 293.8 111.8 182.0 2005 5.4 313.4 130.3 183.1 2006 5.4 322.0 141.8 180.2 2007 1.8 299.5 130.7 168.8 Years thereafter 8.0 2,807.9 977.7 1,830.2 ------------------------------------------------------------------------------ Total minimum lease payments 31.2 $4,368.5 $1,671.1 $2,697.4 ======== ======== ======== Executory costs 7.1 ----------------------------------------- Net minimum lease payments 24.1 Interest portion 8.3 ----------------------------------------- Present value of net minimum lease payments 15.8 Less current portion 1.8 ----------------------------------------- Noncurrent portion $14.0 ----------------------------------------- OE invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. CEI and TE established the Shippingport Capital Trust to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport capital trust arrangements effectively reduce lease costs related to those transactions. 5. CAPITALIZATION: (A) RETAINED EARNINGS- There are no restrictions on retained earnings for payment of cash dividends on FirstEnergy's common stock. (B) EMPLOYEE STOCK OWNERSHIP PLAN- An ESOP Trust funds most of the matching contribution for FirstEnergy's 401(k) savings plan. All full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. In 2002, 2001 and 2000, 1,151,106 shares, 834,657 shares and 826,873 shares, respectively, were allocated to employees with the corresponding expense recognized based on the shares allocated method. The fair value of 3,966,269 shares unallocated as of December 31, 2002, was approximately $130.8 million. Total ESOP-related compensation expense was calculated as follows: 2002 2001 2000 (In millions) - --------------------------------------------------------------------------- Base compensation $34.2 $25.1 $18.7 Dividends on common stock held by the ESOP and used to service debt (7.8) (6.1) (6.4) - --------------------------------------------------------------------------- Net expense $26.4 $19.0 $12.3 =========================================================================== (C) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock-based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 2002 2001 2000 - ----------------------------------------------------------------------- Restricted common shares granted 36,922 133,162 208,400 Weighted average market price $36.04 $35.68 $26.63 Weighted average vesting period (years) 3.2 3.7 3.8 Dividends restricted Yes * Yes - ------------------------------------------------------------------------ * FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2002, there were 296,008 stock units outstanding. See Note 9 - Other Information for discussion of stock-based employee compensation expense recognized for restricted stock and EDCP stock units. Stock option activities under the FE Programs for the past three years were as follows: Number of Weighted Average Stock Option Activities Options Exercise Price --------------------------------------------------------------------------- Balance, January 1, 2000 2,153,369 $25.32 (159,755 options exercisable) 24.87 Options granted 3,011,584 23.24 Options exercised 90,491 26.00 Options forfeited 52,600 22.20 Balance, December 31, 2000 5,021,862 24.09 (473,314 options exercisable) 24.11 Options granted 4,240,273 28.11 Options exercised 694,403 24.24 Options forfeited 120,044 28.07 Balance, December 31, 2001 8,447,688 26.04 (1,828,341 options exercisable) 24.83 Options granted 3,399,579 34.48 Options exercised 1,018,852 23.56 Options forfeited 392,929 28.19 Balance, December 31, 2002 10,435,486 28.95 (1,400,206 options exercisable) 26.07 As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 2G - Stock-Based Compensation. (D) PREFERRED AND PREFERENCE STOCK- Penn's 7.75% series has a restriction which prevents early redemption prior to July 2003. All other preferred stock may be redeemed by the Companies in whole, or in part, with 30-90 days' notice. Met-Ed's and Penelec's preferred stock authorization consists of 10 million and 11.435 million shares, respectively, without par value. No preferred shares are currently outstanding for the two companies. The Companies' preference stock authorization consists of 8 million shares without par value for OE; 3 million shares without par value for CEI; and 5 million shares, $25 par value for TE. No preference shares are currently outstanding. (E) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- Annual sinking fund provisions for the Companies' preferred stock are as follows: Redemption Price Per Series Shares Share ------------------------------------------------------------------ CEI $ 7.35C 10,000 $ 100 Penn 7.625% 7,500 100 ------------------------------------------------------------------ Annual sinking fund requirements for the next five years are $1.8 million in each year 2003 through 2006 and $12.3 million in 2007. (F) SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST OR LIMITED PARTNERSHIP HOLDING SOLELY SUBORDINATED DEBENTURES OF SUBSIDIARIES- CEI formed a statutory business trust as a wholly owned financing subsidiary. The trust sold preferred securities and invested the gross proceeds in the 9.00% subordinated debentures of CEI and the sole assets of the trust are the applicable subordinated debentures. Interest payment provisions of the subordinated debentures match the distribution payment provisions of the trust's preferred securities. In addition, upon redemption or payment at maturity of subordinated debentures, the trust's preferred securities will be redeemed on a pro rata basis at their liquidation value. Under certain circumstances, the applicable subordinated debentures could be distributed to the holders of the outstanding preferred securities of the trust in the event that the trust is liquidated. CEI has effectively provided a full and unconditional guarantee of payments due on its trust's preferred securities. Its trust preferred securities are redeemable at 100% of their principal amount at CEI's option beginning in December 2006. Met-Ed and Penelec each formed statutory business trusts for substantially similar transactions as CEI. However, ownership of the respective Met-Ed and Penelec trusts is through separate wholly-owned limited partnerships, of which a wholly-owned subsidiary of each company is the sole general partner. In these transactions, each trust invested the gross proceeds from the sale of its trust preferred securities in the preferred securities of the applicable limited partnership, which in turn invested those proceeds in the 7.35% and 7.34% subordinated debentures of Met-Ed and Penelec, respectively. In each case, the applicable parent company has effectively provided a full and unconditional guarantee of its obligations under its trust's preferred securities. The Met-Ed and Penelec trust preferred securities are redeemable at the option of Met-Ed and Penelec beginning in May 2004 and September 2004, respectively, at 100% of their principal amount. JCP&L formed a limited partnership for a substantially similar transaction; however, no statutory trust is involved. That limited partnership, of which JCP&L is the sole general partner, invested the gross proceeds from the sale of its monthly income preferred securities (MIPS) in JCP&L's 8.56% subordinated debentures. JCP&L has effectively provided a full and unconditional guarantee of its obligations under the limited partnership's MIPS. The limited partnership's MIPS are redeemable at JCP&L's option at 100% of their principal amount. In each of these transactions, interest on the subordinated debentures (and therefore the distributions on trust preferred securities or MIPS) may be deferred for up to 60 months, but the parent company may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full. The following table lists the subsidiary trusts and limited partnership and information regarding their preferred securities outstanding as of December 31, 2002:
Stated Subordinated Maturity Rate Value(a) Debentures - ------------------------------------------------------------------------------------------ (In millions) Cleveland Electric Financing Trust (b) 2031 9.00% $100.0 $103.1 Met-Ed Capital Trust (c) 2039 7.35% $100.0 $103.1 Penelec Capital Trust (c) 2039 7.34% $100.0 $103.1 JCP&L, Capital L.P. (b) 2044 8.56% $125.0 $128.9 - ------------------------------------------------------------------------------------------ (a) The liquidation value is $25 per security. (b) The sole assets of the trust or limited partnership are the parent company's subordinated debentures with the same rate and maturity date as the preferred securities. (c) The sole assets of the trust are the preferred securities of Met-Ed Capital II, L.P. and Penelec Capital II, L.P., respectively, whose sole assets are the parent company's subordinated debentures with the same rate and maturity date as the preferred securities.
(G) LONG-TERM DEBT- Each of the Companies has a first mortgage indenture under which it issues from time to time first mortgage bonds secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. FirstEnergy and its subsidiaries have various debt covenants under their respective financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. The nonpayments debt covenant which could trigger a default is applicable to financing arrangements of FirstEnergy and all of the Companies. The maintenance of minimum fixed charge ratios and debt to capitalization ratios covenants is applicable to financing arrangements of FirstEnergy, the Ohio Companies and Penn. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Companies. Based on the amount of bonds authenticated by the respective mortgage bond trustees through December 31, 2002, the Companies' annual improvement fund requirements for all bonds issued under the various mortgage indentures of the Companies amounts to $61.5 million. OE and Penn expect to deposit funds with their respective mortgage bond trustees in 2003 that will then be withdrawn upon the surrender for cancellation of a like principal amount of bonds, specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement. JCP&L, Met-Ed and Penelec expect to fulfill their sinking and improvement fund obligation by providing bondable property additions and/or retired bonds to the respective mortgage bond trustees. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) ---------------------------------- 2003 $1,698.8 2004 1,603.8 2005 918.5 2006 1,402.2 2007 251.9 ---------------------------------- Included in the table above are amounts for various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. These amounts are $626 million, $266 million and $47 million in 2003, 2004 and 2005, respectively, which represents the next date at which the debt holders may exercise this provision. The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $287.6 million and noncancelable municipal bond insurance policies of $544.1 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letters of credit or policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.00% to 1.375% of the amounts of the letters of credit to the issuing banks and are obligated to reimburse the banks for any drawings thereunder. FirstEnergy had unsecured borrowings of $395 million as of December 31, 2002, under its $500 million long-term revolving credit facility agreement which expires November 29, 2004. FirstEnergy currently pays an annual facility fee of 0.25% on the total credit facility amount. The fee is subject to change based on changes to FirstEnergy's credit ratings. CEI and TE have unsecured letters of credit of approximately $215.9 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. CEI and TE are jointly and severally liable for the letters of credit. In connection with its Beaver Valley Unit 2 sale and leaseback arrangements, OE has similar letters of credit secured by deposits held by its subsidiary, OES Finance (see Note 4). (H) SECURITIZED TRANSITION BONDS- On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of JCP&L, sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. JCP&L does not own nor did it purchase any of the transition bonds, which are included in long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. The transition bonds represent obligations only of the Issuer and are collateralized solely by the equity and assets of the Issuer, which consist primarily of bondable transition property. The bondable transition property is solely the property of the Issuer. Bondable transition property represents the irrevocable right of a utility company to charge, collect and receive from its customers, through a non-bypassable transition bond charge, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the transition bond charge, pursuant to a servicing agreement with the Issuer. JCP&L is entitled to a quarterly servicing fee of $100,000 that is payable from transition bond charge collections. (I) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity except those resulting from transactions with common stockholders. As of December 31, 2002, accumulated other comprehensive income (loss) consisted of a minimum liability for unfunded retirement benefits of $450.2 million, unrealized losses on investments in securities available for sale of $11.4 million, unrealized losses on derivative instrument hedges of $110.2 million and unrealized currency translation adjustments of $91.4 million. See Note 9 - Other Information for discussion of derivative instruments reclassifications to net income. (J) STOCK REPURCHASE PROGRAM- The Board of Directors authorized the repurchase of up to 15 million shares of FirstEnergy's common stock over a three-year period beginning in 1999. Repurchases were made on the open market, at prevailing prices, and were funded primarily through the use of operating cash flows. During 2001 and 2000, FirstEnergy repurchased and retired 550,000 shares (average price of $27.82 per share), and 7.9 million shares (average price of $24.51 per share), respectively. 6. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT: Short-term borrowings outstanding as of December 31, 2002, consisted of $933.1 million of bank borrowings 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 and is required to pay an annual fee of 0.20% on the amount of the entire finance limit. The receivables financing agreement expires in August 2003. FirstEnergy and its subsidiaries have various credit facilities (including a FirstEnergy $1 billion short-term revolving credit facility) with domestic and foreign banks that provide for borrowings of up to $1.084 billion under various interest rate options. To assure the availability of these lines, FirstEnergy and its subsidiaries are required to pay annual commitment fees that vary from 0.125% to 0.20%. These lines expire at various times during 2003. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2002 and 2001, were 2.41% and 3.80%, respectively. 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- FirstEnergy's current forecast reflects expenditures of approximately $3.1 billion for property additions and improvements from 2003-2007, of which approximately $727 million is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $485 million, of which approximately $69 million applies to 2003. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $483 million and $88 million, respectively, as the nuclear fuel is consumed. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. The Companies' maximum potential assessment under the industry retrospective rating plan would be $352.4 million per incident but not more than $40 million in any one year for each incident. The Companies are also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination costs. The Companies have also obtained approximately $1.2 billion of insurance coverage for replacement power costs. Under these policies, the Companies can be assessed a maximum of approximately $68.4 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Companies intend to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies' plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs. (C) GUARANTEES AND OTHER ASSURANCES- As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds and rating-contingent collateralization provisions. As of December 31, 2002, outstanding guarantees and other assurances aggregated $913 million. FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood that such parental guarantees of $856 million as of December 31, 2002 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related contracts is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $26 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions. Various energy supply contracts contain credit enhancement provisions in the form of cash collateral or letters of credit in the event of a reduction in credit rating below investment grade. These provisions vary and typically require more than one rating reduction to fall below investment grade by Standard & Poor's or Moody's Investors Service to trigger additional collateralization by FirstEnergy. As of December 31, 2002, rating-contingent collateralization totaled $31 million. (D) 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 Expenditures" for 2003 through 2007. The Companies are required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 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 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. 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 for the D.C. Circuit 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 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. 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. 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. (E) OTHER LEGAL PROCEEDINGS- Various lawsuits, claims for personal injury, asbestos and property damage and proceedings related to FirstEnergy's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant are described below. TMI-2 was acquired by FirstEnergy in 2001 as part of the merger with GPU. As a result of the 1979 TMI-2 accident, claims for alleged personal injury against JCP&L, Met-Ed, Penelec and GPU had been filed in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by GPU and dismissed the ten initial "test cases" which had been selected for a test case trial. On January 15, 2002, the District Court granted GPU's July 2001 motion for summary judgment on the remaining 2,100 pending claims. On February 14, 2002, plaintiffs filed a notice of appeal to the United States Court of Appeals for the Third Circuit. In December 2002, the Court of Appeals refused to hear the appeal which effectively ended further legal action for those claims. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory. In May 2001, the court denied without prejudice the defendants' motion seeking decertification of the class. Discovery continues in the class action, but no trial date has been set. In October 2001, the court held argument on the plaintiffs' motion for partial summary judgment, which contends that JCP&L is bound to several findings of the NJBPU investigation. The plaintiffs' motion was denied by the Court in November 2001 and the plaintiffs' motion to file an appeal of this decision was denied by the New Jersey Appellate Division. JCP&L has also filed a motion for partial summary judgment that is currently pending before the Superior Court. FirstEnergy is unable to predict the outcome of these matters. (F) OTHER COMMITMENTS AND CONTINGENCIES- GPU made significant investments in foreign businesses and facilities through its GPU Capital and GPU Power subsidiaries. Although FirstEnergy will attempt to mitigate its risks related to foreign investments, it faces additional risks inherent in operating in such locations, including foreign currency fluctuations. EI Barranquilla, a wholly owned subsidiary of GPU Power, is a 28.67% equity investor in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA), which owns a Colombian independent power generation project. GPU Power is committed, under certain circumstances, to make additional standby equity contributions of $21.3 million, which FirstEnergy has guaranteed. The total outstanding senior debt of the TEBSA project is $254 million as of December 31, 2002. The lenders include the Overseas Private Investment Corporation, US Export Import Bank and a commercial bank syndicate. FirstEnergy has guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $5.9 million (subject to escalation) under the project's operations and maintenance agreement. 8. SEGMENT INFORMATION: FirstEnergy operates under two reportable segments: regulated services and competitive services. The aggregate "Other" segments do not individually meet the criteria to be considered a reportable segment. "Other" consists of interest expense related to the 2001 merger acquisition debt; the corporate support services operating segment and the international businesses acquired in the 2001 merger. The international business assets reflected in the 2001 "Other" assets amount included assets in the United Kingdom identified for divestiture (see Note 3 - Divestitures) which were sold in 2002. As those assets were in the process of being sold, their performance was not being reviewed by a chief operating decision maker and in accordance with SFAS 131, "Disclosures about Segments of an Enterprise and Related Information," did not qualify as an operating segment. The remaining assets and revenues for the corporate support services and the remaining international businesses were below the quantifiable threshold for operating segments for separate disclosure as "reportable segments." FirstEnergy's primary segment is its regulated services segment, which includes eight electric utility operating companies in Ohio, Pennsylvania and New Jersey that provide electric transmission and distribution services. Its other material business segment consists of the subsidiaries that operate unregulated energy and energy-related businesses. The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. It also provides generation services to regulated franchise customers who have not chosen a competing generation supplier. The regulated services segment obtains a portion of its required generation through power supply agreements with the competitive services segment. The competitive services segment includes all domestic unregulated energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation and sourcing of commodity requirements, as well as other competitive energy-application services. Competitive products are increasingly marketed to customers as bundled services. Segment financial data in 2001 and 2000 have been reclassified to conform with the current year business segment organizations and operations. Changes in the current year methodology for computing revenues and expenses used in management reporting for the Competitive Services segment have been reflected in reclassified 2001 and 2000 financial results. Methodology changes included using a fixed rate revenues calculation for the Competitive Services segment's power sales agreement with the Regulated Services segment. This change, when applied to previously reported results, caused lower revenues, income taxes and net income as compared to prior calculated amounts and, correspondingly, reduced purchased power expenses and increased income taxes and net income for the Regulated Services segment. Financial data for these business segments are as follows:
Segment Financial Information ----------------------------- Regulated Competitive Reconciling Services Services Other Adjustments Consolidated --------- ----------- ----- ----------- ------------ (In millions) 2002 ---- External revenues $ 8,794 $3,015 $ 330 $ 13 (a) $12,152 Internal revenues 1,052 1,666 478 (3,196)(b) -- Total revenues 9,846 4,681 808 (3,183) 12,152 Depreciation and amortization 1,034 30 42 -- 1,106 Net interest charges 591 46 367 (58)(b) 946 Income taxes 748 (85) (114) -- 549 Income before cumulative effect of a change in accounting 997 (119) (192) -- 686 Net income 997 (119) (249) -- 629 Total assets 29,689 2,281 1,611 -- 33,581 Total goodwill 5,611 285 -- -- 5,896 Property additions 490 403 105 -- 998 2001 ---- External revenues $ 5,729 $2,165 $ 11 $ 94 (a) $ 7,999 Internal revenues 1,645 1,846 350 (3,841)(b) -- Total revenues 7,374 4,011 361 (3,747) 7,999 Depreciation and amortization 841 21 28 -- 890 Net interest charges 571 25 74 (114)(b) 556 Income taxes 537 (23) (40) -- 474 Income before cumulative effect of a change in accounting 729 (23) (51) -- 655 Net income 729 (32) (51) -- 646 Total assets 28,054 2,981 6,317 -- 37,352 Total goodwill 5,325 276 -- -- 5,601 Property additions 447 375 30 -- 852 2000 ---- External revenues $ 5,415 $1,545 $ 1 $ 68 (a) $ 7,029 Internal revenues 1,222 2,114 306 (3,642)(b) -- Total revenues 6,637 3,659 307 (3,574) 7,029 Depreciation and amortization 919 13 2 -- 934 Net interest charges 558 10 19 (58)(b) 529 Income taxes 365 27 (15) -- 377 Net income 563 39 (3) -- 599 Total assets 14,682 2,685 574 -- 17,941 Total goodwill 1,867 222 -- -- 2,089 Property additions 422 126 40 -- 588 Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting: (a) Principally fuel marketing revenues which are reflected as reductions to expenses for internal management reporting purposes. (b) Elimination of intersegment transactions.
Products and Services - --------------------- Energy Related Electricity Oil & Gas Sales and Year Sales Sales Services ---- ----------- --------- -------------- (In millions) 2002 $9,697 $620 $1,052 2001 6,078 792 693 2000 5,537 582 563
2002 2001 --------------------------- -------------------------- Geographic Information Revenues Assets Revenues Assets - ---------------------- -------- ------ -------- ------ (In millions) United States $11,908 $32,823 $7,991 $32,187 Foreign countries* 244 758 8 5,165 ------- ------- ------ ------- Total $12,152 $33,581 $7,999 $37,352 ======= ======= ====== ======= * See Note 3 for discussion of future divestitures of international operations.
9. OTHER INFORMATION: The following financial data provides supplemental information to the consolidated financial statements and notes previously reported in 2001 and 2000: (A) Consolidated Statements of Cash Flows 2002 2001 2000 ---- ---- ---- (In Thousands) Other Cash Flows From Operating Activities: Accrued taxes $ 37,623 $ 8,915 $ (84) Accrued interest (25,444) 117,520 (8,853) Retail rate refund obligation payments (43,016) -- -- Interest rate hedge -- (132,376) -- Prepayments and other 132,980 (146,741) (21,975) All other 113,371 (97,882) 76,441 ------------------------------------------------------------------------------ Total-Other $215,514 $(250,564) $ 45,529 ============================================================================== Other Cash Flows from Investing Activities: Retirements and transfers $ 29,619 $ 40,106 $ (11,721) Nonutility generation trusts investments 49,044 -- -- Nuclear decommissioning trust investments (86,221) (73,381) (30,704) Aquila notes receivable (91,335) -- -- Other comprehensive income 8,745 (49,653) -- Other investments (16,689) (116,285) (25,481) All other 52,482 (34,313) (52,289) ------------------------------------------------------------------------------ Total-Other $(54,355) $(233,526) $(120,195) ============================================================================== (B) Consolidated Statements of Taxes 2002 2001 2000 ---- ---- ---- (In Thousands) Other Accumulated Deferred Income Taxes at December 31: Retirement Benefits $(381,285) $(133,282) $(60,491) Oyster Creek securitization (Note 5H) 202,447 -- -- Purchase accounting basis differences (2,657) (147,450) -- Sale of generating assets (11,786) 207,787 -- Provision for rate refund (29,370) (46,942) -- All other (193,497) (203,809) 22,767 --------- --------- -------- Total-Other $(416,148) $(323,696) $(37,724) ========= ========= ======== (C) Revenues - Independent System Operator (ISO) Transactions FirstEnergy's regulated and competitive subsidiaries record purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." The aggregate purchase and sales transactions for the three years ended December 31, 2002, are summarized as follows: 2002 2001 2000 - -------------------------------------------------------------------- (Millions) Sales $453 $142 $315 Purchases 687 204 271 - -------------------------------------------------------------------- FirstEnergy's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from the PJM ISO from power sales (as reflected in the table above) during periods when FirstEnergy had additional available power capacity. Revenues also include sales by FirstEnergy of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when FirstEnergy required additional power to meet its retail load requirements and, secondarily, to make sales to the wholesale market. (D) Stock Based Compensation Stock-based employee compensation expense recognized for the FE Programs' restricted stock during 2002, 2001 and 2000 totaled $2,259,000, $1,342,000 and $1,104,000, respectively. In addition, stock-based employee compensation expense of $206,000, $1,637,000 and $1,646,000 during 2002, 2001 and 2000, respectively, was recognized for EDCP stock units (see Note 5C - Stock Compensation Plans for further disclosure). (E) SFAS 115 Activity All other investments included under Investments other than cash and cash equivalents in the table in Note 2J - Supplemental Cash Flows Information include available-for-sale securities, at fair value, with the following results: 2002 2001 2000 - ------------------------------------------------------------------------- (In thousands) Unrealized holding gains $ 202 $2,236 $992 Unrealized holding losses 4,991 432 70 Proceeds from sales 7,875 25 66 Gross realized gains 31 -- 46 Gross realized losses -- 3 -- - ------------------------------------------------------------------------- (F) Derivative Instruments Reclassifications to Net Income Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity except those resulting from transactions with common stockholders (see Note 5I - Comprehensive Income for further disclosure). Other comprehensive income (loss) reclassified to net income in 2002 and 2001 totaled $(9.9) million and $30.7 million, respectively. These amounts were net of income taxes in 2002 and 2001 of $(6.8) million and $21.7 million, respectively. There were no reclassifications to net income in 2000. 10. Other Recently issued Accounting Standards FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. FirstEnergy does not believe that implementation of FIN 45 will be material but it will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements, the sale of preferred securities and debt secured by bondable property, and which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. FirstEnergy currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. In addition to the entities FirstEnergy is currently consolidating it believes that the PNBV Capital Trust, which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of OE's interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require consolidation. Ownership of the trust includes a three-percent equity interest by a nonaffiliated party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46 would change the characterization of the PNBV trust investment to a lease obligation bond investment. Also, consolidation of the outside minority interest would be required, which would increase assets and liabilities by $12.0 million. 11. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
March 31, June 30, September 30, December 31, Three Months Ended 2002 2002 2002 2002 - ----------------------------------------------------------------------------------------------------------------- (In millions, except per share amounts) Revenues (a) $2,762.0 $2,898.5 $3,451.2 $3,040.3 Expenses (a) 2,336.5 2,230.4 2,681.7 2,721.2 - ----------------------------------------------------------------------------------------------------------------- Income Before Interest and Income Taxes 425.5 668.1 769.5 319.1 Net Interest Charges 259.8 250.3 220.4 215.8 Income Taxes 80.9 184.5 238.8 45.3 - ----------------------------------------------------------------------------------------------------------------- Income Before Cumulative Effect of Accounting Change 84.8 233.3 310.3 58.0 Cumulative Effect of Accounting Change (Net of Income Taxes) (Note 3) 31.7 -- -- (88.8) - ----------------------------------------------------------------------------------------------------------------- Net Income (Loss) $ 116.5 $ 233.3 $ 310.3 $ (30.8) ================================================================================================================= Basic Earnings (Loss) Per Share of Common Stock: Before Cumulative Effect of Accounting Change $ .29 $ .80 $ 1.06 $ .20 Cumulative Effect of Accounting Change (Net of Income Taxes) (Note 3) .11 -- -- (.30) - ----------------------------------------------------------------------------------------------------------------- Basic Earnings (Loss) Per Share of Common Stock $ .40 $ .80 $ 1.06 $ (.10) - ----------------------------------------------------------------------------------------------------------------- Diluted Earnings (Loss) Per Share of Common Stock: Before Cumulative Effect of Accounting Change $ .29 $ .79 $ 1.05 $ .20 Cumulative Effect of Accounting Change (Net of Income Taxes) (Note 3) .11 -- -- (.30) - ----------------------------------------------------------------------------------------------------------------- Diluted Earnings (Loss) Per Share of Common Stock $ .40 $ .79 $ 1.05 $ (.10) =================================================================================================================
March 31, June 30, September 30, December 31, Three Months Ended 2001 2001 2001 2001(b) - ----------------------------------------------------------------------------------------------------------------- (In millions, except per share amounts) Revenues $1,985.7 $1,804.1 $1,951.6 $2,257.9 Expenses 1,669.4 1,416.7 1,412.1 1,816.0 - ----------------------------------------------------------------------------------------------------------------- Income Before Interest and Income Taxes 316.3 387.4 539.5 441.9 Net Interest Charges 126.3 121.0 124.1 184.3 Income Taxes 83.8 120.4 181.3 89.0 - ----------------------------------------------------------------------------------------------------------------- Income Before Cumulative Effect of Accounting Change 106.2 146.0 234.1 168.6 Cumulative Effect of Accounting Change (Net of Income Taxes) (Note 2J) (8.5) -- -- -- - ----------------------------------------------------------------------------------------------------------------- Net Income $ 97.7 $ 146.0 $ 234.1 $ 168.6 ================================================================================================================= Basic Earnings Per Share of Common Stock: Before Cumulative Effect of Accounting Change $ .49 $ .67 $ 1.07 $ .64 Cumulative Effect of Accounting Change (Net of Income Taxes) (Note 2J) (.04) -- -- -- - ----------------------------------------------------------------------------------------------------------------- Basic Earnings Per Share of Common Stock $ .45 $ .67 $ 1.07 $ .64 - ----------------------------------------------------------------------------------------------------------------- Diluted Earnings Per Share of Common Stock: Before Cumulative Effect of Accounting Change $ .49 $ .67 $ 1.06 $ .64 Cumulative Effect of Accounting Change (Net of Income Taxes) (Note 2J) (.04) -- -- -- - ----------------------------------------------------------------------------------------------------------------- Diluted Earnings Per Share of Common Stock $ .45 $ .67 $ 1.06 $ .64 ================================================================================================================= (a) 2002 revenues and expenses related to trading activities reflect reclassifications as a result of implementing EITF Issue No. 02-03 (see Note 2C - Revenues). (b) Results for the former GPU companies are included from the November 7, 2001 acquisition date through December 31, 2001.
12. PRO FORMA COMBINED CONDENSED FIRSTENERGY STATEMENTS OF INCOME (UNAUDITED): On November 7, 2001, the merger of FirstEnergy and GPU became effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000 (Merger Agreement). As a result of the merger, GPU's former wholly owned subsidiaries, including JCP&L, Met-Ed and Penelec, (collectively, the Former GPU Companies), became wholly owned subsidiaries of FirstEnergy. Under the terms of the Merger Agreement, GPU shareholders received the equivalent of $36.50 for each share of GPU common stock they owned, payable in cash and/or FirstEnergy common stock. GPU shareholders receiving FirstEnergy shares received 1.2318 shares of FirstEnergy common stock for each share of GPU common stock they exchanged. The cash portion of the merger consideration was approximately $2.2 billion and nearly 73.7 million shares of FirstEnergy common stock were issued to GPU shareholders for the share portion of the transaction consideration. The merger was accounted for by the purchase method of accounting and, accordingly, the Consolidated Statements of Income include the results of the Former GPU Companies beginning November 7, 2001. The assets acquired and liabilities assumed were recorded at estimated fair values as determined by FirstEnergy's management based on information currently available and on current assumptions as to future operations. The merger purchase accounting adjustments, which were recorded in the records of GPU's direct subsidiaries, primarily consist of: (1) revaluation of GPU's international operations to fair value; (2) revaluation of property, plant and equipment; (3) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (4) recognizing additional obligations related to retirement benefits; and (5) recognizing estimated severance and other compensation liabilities. Other assets and liabilities were not adjusted since they remain subject to rate regulation on a historical cost basis. The severance and compensation liabilities are based on anticipated workforce reductions reflecting duplicate positions primarily related to corporate support groups including finance, legal, communications, human resources and information technology. The workforce reductions represent the expected reduction of approximately 700 employees at a cost of approximately $140 million. Merger related staffing reductions began in late 2001 and the remaining reductions are anticipated to occur through 2003 as merger-related transition assignments are completed. The merger greatly expanded the size and scope of our electric business and the goodwill recognized primarily relates to the regulated services segment. The combination of FirstEnergy and GPU was a key strategic step in FirstEnergy achieving its vision of being the leading energy and related services provider in the region. The merger combined companies with the management, employee experience and technical expertise, retail customer base, energy and related services platform and financial resources to grow and succeed in a rapidly changing energy marketplace. The merger also allowed for a natural alliance of companies with adjoining service areas and interconnected transmission systems to eliminate duplicative costs, maximize efficiencies and increase management and operational flexibility in order to enhance operations and become a more effective competitor. Under the purchase method of accounting, tangible and identifiable intangible assets acquired and liabilities assumed are recorded at their estimated fair values. The excess of the purchase price, including estimated fees and expenses related to the merger, over the net assets acquired (which included existing goodwill of $1.9 billion), is classified as goodwill and amounts to an additional $2.3 billion. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed on the date of acquisition. ------------------------------------------------------------- (In millions) ------------- Current assets................... $ 1,027 Goodwill......................... 3,698 Regulatory assets................ 4,352 Other............................ 5,595 ------------------------------------------------------------- Total assets acquired........ 14,672 ------------------------------------------------------------- Current liabilities.............. (2,615) Long-term debt................... (2,992) Other............................ (4,785) ------------------------------------------------------------- Total liabilities assumed.... (10,392) Net assets acquired pending sale. 566 ------------------------------------------------------------- Net assets acquired.............. $ 4,846 ------------------------------------------------------------- During 2002, certain pre-acquisition contingencies and other final adjustments to the fair values of the assets acquired and liabilities assumed were reflected in the final allocation of the purchase price. These adjustments primarily related to: (1) final actuarial calculations related to pension and postretirement benefit obligations; (2) updated valuations of GPU's international operations as of the date of the merger; (3) establishment of a reserve for deferred energy costs recognized prior to the merger; and (4) return to accrual adjustments for income taxes. As a result of these adjustments, goodwill increased by approximately $290 million, which is attributable to the regulated services segment. The following pro forma combined condensed statements of income of FirstEnergy give effect to the FirstEnergy/GPU merger as if it had been consummated on January 1, 2000, with the purchase accounting adjustments actually recognized in the business combination. The pro forma combined condensed financial statements have been prepared to reflect the merger under the purchase method of accounting with FirstEnergy acquiring GPU. In addition, the pro forma adjustments reflect a reduction in debt from application of the proceeds from certain pending divestitures as well as the related reduction in interest costs. Year Ended December 31, ----------------------- 2001 2000 ---- ---- (In millions, except per share amounts) Revenues $12,108 $11,703 Expenses 9,768 9,377 - ------------------------------------------------------------------------- Income Before Interest and Income Taxes 2,340 2,326 Net Interest Charges 941 977 Income Taxes 561 527 - ------------------------------------------------------------------------- Net Income $ 838 $ 822 - ------------------------------------------------------------------------- Earnings per Share of Common Stock $ 2.87 $ 2.77 - ------------------------------------------------------------------------- EX-21 10 fe_ex21.txt EX. 21 LIST OF SUBS - FE EXHIBIT 21 FIRSTENERGY CORP. LIST OF SUBSIDIARIES OF THE REGISTRANT AT DECEMBER 31, 2002 Ohio Edison Company - Incorporated in Ohio The Cleveland Electric Illuminating Company - Incorporated in Ohio The Toledo Edison Company - Incorporated in Ohio Centerior Service Company - Incorporated in Ohio FirstEnergy Properties Company - Incorporated in Ohio FirstEnergy Ventures Corporation - Incorporated in Ohio FirstEnergy Facilities Services Group, LLC - Incorporated in Ohio FirstEnergy Securities Transfer Company - Incorporated in Ohio FirstEnergy Service Company - Incorporated in Ohio FirstEnergy Solutions Corp. - Incorporated in Ohio MARBEL Energy Corporation - Incorporated in Ohio FirstEnergy Nuclear Operating Company - Incorporated in Ohio FirstEnergy Holdings, LLC - Incorporated in Ohio FE Acquisition Corp. - Incorporated in Ohio American Transmission Systems, Inc. - Incorporated in Ohio FELHC, Inc. - Incorporated in Ohio Jersey Central Power & Light Company - Incorporated in New Jersey Metropolitan Edison Company - Incorporated in Pennsylvania Pennsylvania Electric Company - Incorporated in Pennsylvania GPU Advanced Resources, Inc. - Incorporated in Delaware GPU Capital, Inc. - Incorporated in Delaware GPU Diversified Holdings, LLC - Incorporated in Delaware GPU Nuclear, Inc. - Incorporated in New Jersey GPU Power, Inc. - Incorporated in Delaware GPU Service, Inc. - Incorporated in Pennsylvania GPU Telecom Services, Inc. - Incorporated in Delaware MYR Group, Inc. - Incorporated in Delaware Statement of Differences ------------------------ Exhibit Number 21, List of Subsidiaries of the Registrant at December 31, 2002, is not included in the printed document. EX-23 11 fe_ex23.txt EX. 23 PWC CONSENT - FE EXHIBIT 23 FIRSTENERGY CORP. CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-48587 and 333-102074) and Form S-8 (Nos. 333-48651, 333-56094, 333-58279, 333-67798, 333-72764, 333-72766, 333-72768, 333-75985, 333-81183, 333-89356 and 333-101472) of FirstEnergy Corp. of our report dated February 28, 2003 relating to the consolidated financial statements, which appears in the Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 28, 2003 relating to the financial statement schedule, which appears in this Form 10-K. PricewaterhouseCoopers LLP Cleveland, Ohio March 24, 2003 EX-99 12 fe_ex99-1.txt EX. 99-1 CEO CERTIFICATION LETTER - HPB Exhibit 99.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Reports of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Metropolitan Edison Company, and Pennsylvania Electric Company ("Companies") on Form 10-K for the year ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Reports"), I, H. Peter Burg, Chief Executive Officer of each of the Companies, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: (1) Each of the Reports fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in each of the Reports fairly presents, in all material respects, the financial condition and results of operations of the Company to which it relates. /s/ H. Peter Burg ----------------------- H. Peter Burg Chief Executive Officer March 24, 2003 EX-99 13 fe_ex99-2.txt EX. 99-2 CEO CERTIFICATION LETTER - RHM Exhibit 99.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Reports of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company ("Companies") on Form 10-K for the year ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Reports"), I, Richard H. Marsh, Senior Vice President and Chief Financial Officer of each of the Companies, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: (1) Each of the Reports fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in each of the Reports fairly presents, in all material respects, the financial condition and results of operations of the Company to which it relates. /s/Richard H. Marsh ------------------------- Richard H. Marsh Senior Vice President and Chief Financial Officer March 24, 2003 EX-12 14 oe_ex12-2.txt EX. 12-2 FIXED CHARGE RATIO - OE EXHIBIT 12.2 Page 1 OHIO EDISON COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
Year Ended December 31, ------------------------------------------------------------- 1998 1999 2000 2001 2002 -------- -------- -------- -------- -------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items............................ $301,320 $297,689 $336,456 $350,212 $363,483 Interest and other charges, before reduction for amounts capitalized........................................ 235,317 225,358 211,364 187,890 144,170 Provision for income taxes................................... 191,261 191,835 212,580 239,135 266,561 Interest element of rentals charged to income (a)............ 115,310 113,804 109,497 104,507 102,469 --------- --------- --------- --------- --------- Earnings as defined........................................ $843,208 $828,686 $869,897 $881,744 $876,683 ======== ======== ======== ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K: Interest on long-term debt................................... $184,915 $178,217 $165,409 $150,632 $119,123 Other interest expense....................................... 34,976 31,971 31,451 22,754 14,598 Subsidiaries' preferred stock dividend requirements.......... 15,426 15,170 14,504 14,504 10,449 Adjustments to subsidiaries' preferred stock dividends to state on a pre-income tax basis......................... 2,892 2,770 2,296 2,481 2,661 Interest element of rentals charged to income (a)............ 115,310 113,804 109,497 104,507 102,469 --------- --------- --------- --------- --------- Fixed charges as defined................................... $353,519 $341,932 $323,157 $294,878 $249,300 ======== ======== ======== ======== ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES (b).................................................. 2.39 2.42 2.69 2.99 3.52 ==== ==== ==== ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined. (b) These ratios exclude fixed charges applicable to the guarantee of the debt of a coal supplier aggregating $3,828,000 for the year ended December 31, 1998. The guarantee and related coal supply contract debt expired December 31, 1999.
EXHIBIT 12.2 Page 2 OHIO EDISON COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
Year Ended December 31, ------------------------------------------------------------- 1998 1999 2000 2001 2002 -------- -------- -------- -------- -------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items.......................... $301,320 $297,689 $336,456 $350,212 $363,483 Interest and other charges, before reduction for amounts capitalized...................................... 235,317 225,358 211,364 187,890 144,170 Provision for income taxes................................. 191,261 191,835 212,580 239,135 266,561 Interest element of rentals charged to income (a).......... 115,310 113,804 109,497 104,507 102,469 -------- -------- -------- -------- -------- Earnings as defined...................................... $843,208 $828,686 $869,897 $881,744 $876,683 ======== ======== ======== ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS): Interest on long-term debt................................. $184,915 $178,217 $165,409 $150,632 $119,123 Other interest expense..................................... 34,976 31,971 31,451 22,754 14,598 Preferred stock dividend requirements...................... 27,395 26,717 25,628 25,206 16,959 Adjustments to preferred stock dividends to state on a pre-income tax basis....................... 10,140 9,859 8,976 9,412 7,034 Interest element of rentals charged to income (a).......... 115,310 113,804 109,497 104,507 102,469 -------- -------- -------- -------- -------- Fixed charges as defined plus preferred stock dividend requirements (pre-income tax basis)........... $372,736 $360,568 $340,961 $312,511 $260,183 ======== ======== ======== ======== ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS) (b)................................. 2.26 2.30 2.55 2.82 3.37 ==== ==== ==== ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined. (b) These ratios exclude fixed charges applicable to the guarantee of the debt of a coal supplier aggregating $3,828,000 for the year ended December 31, 1998. The guarantee and related coal supply contract debt expired December 31, 1999.
EX-13 15 oe_ex13-1.txt EX. 13-1 ANNUAL REPORT - OE OHIO EDISON COMPANY 2002 ANNUAL REPORT TO STOCKHOLDERS Ohio Edison Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. Ohio Edison engages in the generation, distribution and sale of electric energy to communities in an area of 7,500 square miles in central and northeastern Ohio and, through its wholly owned Pennsylvania Power Company subsidiary, 1,500 square miles in western Pennsylvania. It also engages in the sale, purchase and interchange of electric energy with other electric companies. Contents Page - -------- ---- Selected Financial Data.................................... 1 Management's Discussion and Analysis....................... 2-11 Consolidated Statements of Income.......................... 12 Consolidated Balance Sheets................................ 13 Consolidated Statements of Capitalization.................. 14-15 Consolidated Statements of Common Stockholder's Equity..... 16 Consolidated Statements of Preferred Stock................. 16 Consolidated Statements of Cash Flows...................... 17 Consolidated Statements of Taxes........................... 18 Notes to Consolidated Financial Statements................. 19-32 Reports of Independent Accountants......................... 33-34
OHIO EDISON COMPANY SELECTED FINANCIAL DATA 2002 2001 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------- (In thousands) Operating Revenues.......................... $2,948,675 $3,056,464 $2,726,708 $2,686,949 $2,519,662 --------------------------------------------------------------- Operating Income............................ $ 461,685 $ 466,819 $ 482,321 $ 473,042 $ 486,920 --------------------------------------------------------------- Income Before Extraordinary Item............ $ 363,483 $ 350,212 $ 336,456 $ 297,689 $ 301,320 --------------------------------------------------------------- Net Income.................................. $ 363,483 $ 350,212 $ 336,456 $ 297,689 $ 270,798 --------------------------------------------------------------- Earnings on Common Stock.................... $ 356,973 $ 339,510 $ 325,332 $ 286,142 $ 258,828 --------------------------------------------------------------- Total Assets................................ $7,800,741 $7,915,953 $8,154,151 $8,700,746 $8,923,826 --------------------------------------------------------------- Capitalization at December 31: Common Stockholder's Equity.............. $2,840,361 $2,671,001 $2,556,992 $2,624,460 $2,681,873 Preferred Stock: Not Subject to Mandatory Redemption.... 100,070 200,070 200,070 200,070 211,870 Subject to Mandatory Redemption........ 13,500 134,250 135,000 140,000 145,000 Long-Term Debt........................... 1,219,347 1,614,996 2,000,622 2,175,812 2,215,042 --------------------------------------------------------------- Total Capitalization................... $4,173,278 $4,620,317 $4,892,684 $5,140,342 $5,253,785 --------------------------------------------------------------- Capitalization Ratios: Common Stockholder's Equity.............. 68.1% 57.8% 52.3% 51.1% 51.0% Preferred Stock: Not Subject to Mandatory Redemption.... 2.4 4.3 4.1 3.9 4.0 Subject to Mandatory Redemption........ 0.3 2.9 2.7 2.7 2.8 Long-Term Debt........................... 29.2 35.0 40.9 42.3 42.2 --------------------------------------------------------------- Total Capitalization................... 100.0% 100.0% 100.0% 100.0% 100.0% --------------------------------------------------------------- Distribution Kilowatt-Hour Deliveries (Millions): Residential.............................. 10,233 9,646 9,432 9,483 8,773 Commercial............................... 7,994 7,967 8,221 8,238 7,590 Industrial............................... 10,672 10,995 11,631 11,310 10,803 Other.................................... 154 152 151 151 150 --------------------------------------------------------------- Total.................................... 29,053 28,760 29,435 29,182 27,316 --------------------------------------------------------------- Customers Served: Residential.............................. 1,041,825 1,033,414 1,014,379 1,016,793 1,004,552 Commercial............................... 119,771 118,469 116,931 115,581 113,820 Industrial............................... 4,500 4,573 4,569 4,627 4,598 Other.................................... 1,756 1,664 1,606 1,539 1,476 --------------------------------------------------------------- Total.................................... 1,167,852 1,158,120 1,137,485 1,138,540 1,124,446 --------------------------------------------------------------- Number of Employees ........................ 1,569 1,618 1,647 2,734 2,832
OHIO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Corporate Separation - -------------------- Beginning on January 1, 2001, Ohio customers were able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. That legislation required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Ohio Edison (OE) and Pennsylvania Power (Penn) continue to deliver power to homes and businesses through their existing distribution systems and maintain the "provider of last resort" (PLR) obligations under their respective rate plans. As a result of the transition plan, FirstEnergy's electric utility operating companies (EUOC) entered into power supply agreements whereby FirstEnergy Solutions Corp. (FES) purchases all of the EUOC nuclear generation, and leases EUOC fossil generating facilities. The Ohio EUOC and Penn are "full requirements" customers of FES to enable them to meet their PLR responsibilities in their respective service areas. The effect on OE's and Penn's (Companies) reported results of operations during 2001 from FirstEnergy's corporate separation plan and the Companies' sale of transmission assets to American Transmission Systems, Inc. (ATSI) in September 2000, are summarized in the following table:
Corporate Restructuring - 2001 Income Statement Effects ------------------------------------------------------- Increase (Decrease) Corporate Separation ATSI Total ---------- ---- ----- (In millions) Operating Revenues: Power supply agreement with FES........ $ 355.9 $ -- $ 355.9 Generating units rent.................. 178.8 -- 178.8 Ground lease with ATSI................. -- 3.1 3.1 -------------------------------------------------------------------------------------- Total Operating Revenues Effect........ $ 534.7 $ 3.1 $ 537.8 ====================================================================================== Operating Expenses and Taxes: Fossil fuel costs...................... $ (264.3)(a) $ -- $ (264.3) Purchased power costs.................. 1,025.9 (b) -- 1,025.9 Other operating costs.................. (157.1)(a) 28.6 (d) (128.5) Provision for depreciation and amortization -- (12.9)(e) (12.9) General taxes.......................... (4.8)(c) (15.2)(e) (20.0) Income taxes........................... (23.4) 5.2 (18.2) -------------------------------------------------------------------------------------- Total Operating Expenses Effect........ $ 576.3 $ 5.7 $ 582.0 ====================================================================================== Other Income............................. $ -- $ 10.7 (f) $ 10.7 ====================================================================================== (a) Transfer of fossil operations to FirstEnergy Generation Company (FGCO). (b) Purchased power from power supply agreement (PSA). (c) Payroll taxes related to employees transferred to FGCO. (d) Transmission services received from ATSI. (e) Depreciation and property taxes related to transmission assets sold to ATSI. (f) Interest on note receivable from ATSI.
Results of Operations - --------------------- Earnings on common stock in 2002 increased 5.2% to $357.0 million in 2002 from $339.5 million in 2001 and $325.3 million in 2000. The earnings increase in 2002 primarily resulted from reduced financing costs, which more than offset lower operating income and reduced investment income. Excluding the effects shown in the table above, earnings on common stock increased by 14.7% in 2001 from 2000, being favorably affected by reduced operating expenses and taxes, and lower net interest charges, which were substantially offset by reduced operating revenues. Operating revenues decreased by $107.8 million or 3.5% in 2002 compared with 2001. The lower revenues reflected the effects of a sluggish national economy on our service area, shopping by Ohio customers for alternative energy providers and changes in wholesale revenues. Retail kilowatt-hour sales declined by 8.7% in 2002 from the prior year, with declines in all customer sectors (residential, commercial and industrial), resulting in a $73.1 million reduction in generation sales revenue. Our lower generation kilowatt-hour sales resulted primarily from customer choice in Ohio. Sales of electric generation by alternative suppliers as a percent of total sales delivered in our franchise area increased to 20.9% in 2002 from 12.5% in 2001, while our share of electric generation sales in our franchise areas decreased by 8.4% compared to the prior year. Distribution deliveries increased 1.0% in 2002 compared with 2001, which increased revenues from electricity throughput by $18.5 million in 2002 from the prior year. The higher distribution deliveries resulted from additional residential demand due to warmer summer weather that was offset in part by the effect that continued sluggishness in the economy had on demand by commercial and industrial customers. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, further reduced operating revenues by $27.6 million in 2002 from the prior year. These revenue reductions are deferred for future recovery under our transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers decreased by $18.0 million in 2002 compared to 2001, due to a decline in market prices. Excluding the effects shown in the table above, operating revenues decreased by $208.0 million or 7.6% in 2001 from 2000. Customer choice in Ohio and the influence of a declining national economy on our regional business activity combined to lower operating revenues. Electric generation services provided by other suppliers in the Companies' service area increased to 12.5% of total energy delivered from 1.5% in 2000. Overall, retail generation sales declined in all customer categories resulting in a 13.1% reduction in kilowatt-hour sales from the prior year. As part of Ohio's electric utility restructuring law, the implementation of a 5% reduction in generation charges for residential customers reduced operating revenues by approximately $26.6 million in 2001, compared to 2000. Distribution deliveries declined 2.3% in 2001 from the prior year reflecting the impact of a weaker economy that contributed to lower commercial and industrial kilowatt-hour sales. Operating revenues were also lower in 2001 from the prior year due to the absence of revenues associated with the low-income payment plan now administered by the Ohio Department of Development; there was also a corresponding reduction in other operating costs associated with that change. Revenues from kilowatt-hour sales to wholesale customers declined by $54.3 million in 2001 from 2000, with a corresponding 42.0% reduction in kilowatt-hour sales. Changes in KWH Sales 2002 2001 --------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (8.7)% (13.1)% Wholesale............................. 10.6% (42.0)% --------------------------------------------------------------------- Total Electric Generation Sales......... (0.6)% (20.5)% ===================================================================== Distribution Deliveries: Residential........................... 6.1% 2.3% Commercial and industrial............. (1.6)% (4.5)% --------------------------------------------------------------------- Total Distribution Deliveries........... 1.0% (2.3)% ===================================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $102.7 million in 2002 and increased by $345.3 million in 2001 from 2000. Excluding the effects of restructuring, total 2001 operating expenses and taxes were $236.7 million lower than the prior year. The following table presents changes from the prior year by expense category excluding the impact of restructuring on 2001 changes. Operating Expenses and Taxes - Changes 2002 2001 --------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel and purchased power..................... $(109.6) $ (84.1) Nuclear operating costs...................... (28.9) 14.7 Other operating costs........................ 47.1 (14.6) --------------------------------------------------------------------- Total operation and maintenance expenses... (91.4) (84.0) Provision for depreciation and amortization.. (54.1) (140.8) General taxes................................ 23.5 (52.3) Income taxes................................. 19.3 40.4 --------------------------------------------------------------------- Total operating expenses and taxes......... $(102.7) $(236.7) ===================================================================== Lower fuel and purchased power costs in 2002, compared to 2001, resulted from a $114.4 million reduction in power purchased from FES, reflecting lower kilowatt-hours purchased due to reduced kilowatt-hour sales and lower unit prices. Nuclear operating costs decreased $28.9 million, primarily due to one less refueling outage in 2002 compared to the prior year. The $47.1 million increase in other operating costs resulted principally from higher employee benefit costs and, to a lesser extent, increased distribution costs due in part to storm damage. The decrease in fuel and purchased power costs in 2001, compared to 2000, reflects the transfer of fossil operations to FGCO, with the Companies' power requirements being provided under the PSA. Nuclear operating costs increased by $14.7 million in 2001 from the prior year due to two refueling outages compared to one refueling outage in 2000; however, the Perry Plant also experienced two unplanned outages in 2001. Other operating costs decreased by $14.6 million in 2001 from the prior year, reflecting a reduction in low-income payment plan customer costs, lower storm damage costs, the absence of costs incurred in 2000 related to the development of a distribution communications system, reduced uncollectible accounts and customer program expenses, offset in part by the absence in 2001 of gains from the sale of emission allowances. Charges for depreciation and amortization decreased by $54.1 million in 2002 from 2001 primarily due to higher shopping incentive deferrals and tax-related deferrals under OE's transition plan. In 2001, depreciation and amortization decreased by $140.8 million from the prior year due to lower incremental transition cost amortization and new deferrals for shopping incentives under FirstEnergy's Ohio transition plan compared to the accelerated cost recovery in connection with our prior regulatory plan. General taxes increased by $23.5 million in 2002 from 2001 principally due to additional property taxes and the absence in 2002 of a one-time benefit of $15 million resulting from the successful resolution of certain property tax issues in the prior year. In 2001, general taxes decreased by $52.3 million from 2000 due to reduced property taxes and other state tax changes in connection with the Ohio electric industry restructuring and the one-time $15 million benefit. The reduction in general taxes was partially offset by $38.0 million of new Ohio franchise taxes in 2001, which are classified as state income taxes on the Consolidated Statements of Income. Other Income Other income decreased by $26.4 million in 2002 from the prior year, primarily due to lower investment income. Net Interest Charges Net interest charges continued to trend lower, decreasing by $44.8 million in 2002 and by $16.6 million in 2001, compared to the prior year. We continued to redeem and refinance outstanding debt and preferred stock during 2002 - net redemptions and refinancing activities totaled $542.0 million and $14.5 million, respectively, and will result in annualized savings of $37.1 million. Capital Resources and Liquidity - ------------------------------- Our improving financial position reflects ongoing efforts to increase competitiveness and enhance shareholder value. We have continued to strengthen our financial position over the past five years by improving our fixed charge coverage ratios. Our corporate indenture ratio, which is used to measure our ability to issue first mortgage bonds, increased from 6.21 in 1997 to 11.35 in 2002, which enhances our financial flexibility. Over the same period, our charter ratio, a measure of our ability to issue preferred stock, improved from 2.35 to 5.07 and our common stockholder's equity as a percentage of capitalization rose from approximately 48% at the end of 1997 to 68% at the end of 2002. Over the last five years, we have reduced the average cost of long-term debt from 7.77% in 1997 to 5.77% at the end of 2002. Changes in Cash Position As of December 31, 2002, we had $20.5 million of cash and cash equivalents, compared with $4.6 million as of December 31, 2001. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Our consolidated net cash from operating activities is provided by our regulated energy services. Net cash provided from operating activities was $1.057 billion in 2002 and $668 million in 2001. Cash flows provided from 2002 and 2001 operating activities are as follows: Operating Cash Flows 2002 2001 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 711 $743 Working capital and other............ 346 (75) ------------------------------------------------------------- Total................................ $1,057 $668 ============================================================= (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and major noncash charges. Cash Flows From Financing Activities In 2002, the net cash used for financing activities of $599 million primarily reflects the redemptions of debt and preferred stock shown below. The following table provides details regarding new issues and redemptions during 2002: Securities Issued or Redeemed in 2002 --------------------------------------------------------------- (In millions) New Issues Pollution Control Notes.................... $ 15 Redemptions First Mortgage Bonds....................... $280 Pollution Control Notes.................... 15 Secured Notes.............................. 127 Preferred Stock............................ 221 Other, principally redemption premiums..... 4 ------------------------------------------------------------ $647 Short-term Borrowings, Net...................... $162 ------------------------------------------------------------ In 2001, net cash used for financing activities totaled $432 million, primarily due to the redemption of debt and the payment of common stock dividends to FirstEnergy. We had about $458.2 million of cash and temporary investments and approximately $407.7 million of short-term indebtedness at the end of 2002. Available borrowing capability under bilateral bank facilities totaled $18.5 million as of December 31, 2002. We had the capability to issue $1.7 billion of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests we could issue a total of $3.1 billion of preferred stock (assuming no additional debt was issued) as of the end of 2002. At the end of 2002, our common equity as a percentage of capitalization stood at 68% compared to 58% at the end of 2001. The higher common equity percentage in 2002 compared to 2001 resulted from net redemptions of preferred stock and long-term debt and the increase in retained earnings. Cash Flows From Investing Activities Net cash flows used in investing activities totaled $443 million in 2002. The net cash flows used for investing resulted from loans to associated companies and property additions, which were offset in part by a reduction of the PNBV Capital Trust investment. Expenditures for property additions primarily include expenditures supporting our distribution of electricity. In 2001, net cash flows used in investing activities totaled $249 million, principally due to property additions, the sale of property to affiliates as part of corporate separation and the sale to ATSI discussed above. Our cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, we expect to meet our contractual obligations with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets.
Less than 1-3 3-5 More than Contractual Obligations Total 1 Year Years Years 5 Years - ----------------------------------------------------------------------------------------------------------------- (in millions) Long-term debt................... $1,776 $250 $234 $ 12 $1,280 Short-term borrowings............ 408 408 -- -- -- Preferred stock (1).............. 14 1 2 11 -- Capital leases (2)............... 20 3 9 5 3 Operating leases (2)............. 1,311 74 162 160 915 Purchases (3).................... 239 45 50 62 82 - ------------------------------------------------------------------------------------------------------------- Total....................... $3,768 $781 $457 $250 $2,280 - ------------------------------------------------------------------------------------------------------------- (1) Subject to mandatory redemption (2) Operating lease payments are net of capital trust receipts of $653.9 million (see Note 2). (3) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing
Our capital spending for the period 2003-2007 is expected to be about $391 million (excluding nuclear fuel) of which approximately $139 million applies to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $97 million, of which about $42 million relates to 2003. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $85 million and $41 million, respectively, as the nuclear fuel is consumed. On February 22, 2002, Moody's Investor Service changed its credit rating outlook for FirstEnergy from stable to negative. The change was based upon a decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania Public Utility Commission (PPUC) for reconsideration its decision on the mechanism for sharing merger savings and reversed the PPUC's decisions regarding rate relief and accounting deferrals rendered in connection with its approval of the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed its outlook for FirstEnergy's credit ratings from stable to negative citing recent developments including: damage to the Davis-Besse reactor vessel head (the Companies have no ownership interest in Davis-Besse), the Pennsylvania Commonwealth Court decision, and deteriorating market conditions for some sales of FirstEnergy's remaining non-core assets. On July 31, 2002, Fitch revised its rating outlook for FirstEnergy to negative from stable. The revised outlook reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's judgment about NRG's financial ability to consummate the purchase of four power plants (none owned by the Companies) from FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while NRG's liquidity position added uncertainty to FirstEnergy's sale of power plants to NRG, its ratings would not be affected. S&P found FirstEnergy's cash flows sufficiently stable to support a continued (although delayed) program of debt and preferred stock redemption. S&P noted that it would continue to closely monitor FirstEnergy's progress on various initiatives. On January 21, 2003, S&P indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa (FirstEnergy's Argentina operations), which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining its current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the Jersey Central Power & Light Company rate case, successful hedging of its short power position, and continued capture of projected merger savings. While FirstEnergy anticipates being prepared to restart the Davis-Besse plant in the spring of 2003, the Nuclear Regulatory Commission (NRC) must authorize the unit's restart following a formal inspection process prior to its returning the unit to service. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt could put additional pressure on the Companies' credit ratings. Other Obligations Obligations not included on our Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2, which are reflected in the operating lease payments disclosed above (see Note 2 - Leases). The present value as of December 31, 2002, of these sale and leaseback operating lease commitments, net of trust investments, total $695 million. Interest Rate Risk - ------------------ Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the following table. We are subject to the inherent risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 2, our investment in the PNBV Capital Trust effectively reduces future lease obligations, also reducing interest rate risk. Changes in the market value of our nuclear decommissioning trust funds had been recognized by making corresponding changes to the decommissioning liability, as described in Note 1 - Utility Plant and Depreciation. In conjunction with the adoption of SFAS 143, "Accounting for Asset Retirement Obligations," on January 1, 2003, we reclassified unrealized gains and losses to other comprehensive income (OCI) in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity." While fluctuations in the fair value of our Ohio EUOCs' trust balances will eventually affect earnings (affecting OCI initially) based on the guidance provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from ratepayers the difference between the investments held in trust and their decommissioning obligations. Thus, in absence of disallowed costs, there will be no earning effect from fluctuations in their decommissioning trust balances. As of December 31, 2002, decommissioning trust balances totaled $1.050 billion with $698 million held by our Ohio EUOC and the balance held by our non-Ohio EUOC. As of year end 2002, trust balances included 51% of equity and 49% of debt instruments. The table below presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.
Comparison of Carrying Value to Fair Value - ------------------------------------------------------------------------------------------------------------------ There- Fair 2003 2004 2005 2006 2007 after Total Value - ------------------------------------------------------------------------------------------------------------------ Assets (Dollars in millions) Investments other than Cash and Cash Equivalents: Fixed Income................. $ 31 $306 $184 $ 34 $ 37 $649 $1,241 $1,284 Average interest rate..... 8.0% 7.8% 7.9% 8.2% 8.4% 7.5% 7.7% - ------------------------------------------------------------------------------------------------------------------ Liabilities - ------------------------------------------------------------------------------------------------------------------ Long-term Debt: Fixed rate................... $250 $ 97 $137 $ 6 $ 6 $569 $1,065 $1,150 Average interest rate .... 8.2% 7.3% 7.2% 7.9% 7.9% 7.1% 7.4% Variable rate................ $711 $ 711 $ 711 Average interest rate..... 2.9% 2.9% Short-term Borrowings........ $408 $ 408 $ 408 Average interest rate..... 1.6% 1.6% - ------------------------------------------------------------------------------------------------------------------ Preferred Stock.............. $ 1 $ 1 $ 1 $ 1 $ 10 $ 14 $ 14 Average dividend rate .... 7.6% 7.6% 7.6% 7.6% 7.6% 7.6% - ------------------------------------------------------------------------------------------------------------------
Equity Price Risk - ----------------- Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $148 million and $151 million as of December 31, 2002 and 2001, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $15 million reduction in fair value as of December 31, 2002 (see Note 1K - Supplemental Cash Flows Information). Outlook - ------- Our industry continues to transition to a more competitive environment. In 2001, all our customers could select alternative energy suppliers. We continue to deliver power to residential homes and businesses through our existing distribution systems, which remain regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, we have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters Beginning on January 1, 2001, Ohio customers were able to choose their electricity suppliers. Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of our Ohio customers elects to obtain power from an alternative supplier, we reduce the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive for OE customers), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by the Public Utilities Commission of Ohio (PUCO), PPUC and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of our regulatory assets are expected to continue to be recovered under the provisions of our transition plan as discussed below. Our regulatory assets are as follows: Regulatory Assets as of December 31, ---------------------------------------------------------- Company 2002 2001 ---------------------------------------------------------- (In millions) OE......................... $1,855.9 $2,025.4 Penn....................... 156.9 208.8 ---------------------------------------------------------- Consolidated Total...... $2,012.8 $2,234.2 ========================================================== The transition cost portion of rates provides for recovery of certain amounts not otherwise recoverable in a competitive generation market (such as regulatory assets). Transition costs are paid by all customers whether or not they choose an alternative supplier. Under the PUCO-approved transition plan, we assumed the risk of not recovering up to $250 million of transition revenue if the rate of customers (excluding contracts and full-service accounts) switching from our service to an alternative supplier did not reach 20% for any consecutive twelve-month period by December 31, 2005 - the end of the market development period. That goal was achieved in 2002. Accordingly, OE does not believe that there will be any regulatory action reducing the recoverable transition costs. As part of our Ohio transition plan we are obligated to supply electricity to customers who do not choose an alternative supplier. We are also required to provided 560 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within our service area. Our competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in our franchise area. In 2003, the total peak load forecasted for customers electing to stay with us, including the 560 MW of low cost supply and the load served by our affiliate is 5,820 MW. Environmental Matters We believe we are in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 5C - Environmental Matters). We continue to evaluate our compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W.H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against 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 (CAA). The civil complaint against OE and Penn requests installation of "best available control technology" as well as civil penalties of up to $27,500 per day. Although unable to predict the outcome of these proceedings, we believe the Sammis Plant is in full compliance with the CAA and that the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. 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 effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on our earnings and competitive position. These environmental regulations affect our earnings and competitive position to the extent we compete with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. We believe we are in material compliance with existing regulations, but are unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Significant Accounting Policies - ------------------------------- We prepare our consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect our financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. Our more significant accounting policies are described below. Regulatory Accounting The Companies are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on our costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio and Pennsylvania, a significant amount of regulatory assets have been recorded. As of December 31, 2002, the Companies' regulatory assets totaled $2.0 billion. We continually review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet been billed through the end of the year. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, we reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000. Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. The market values of our pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002, 2001 and 2000, plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, we will not be required to fund our pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to our 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. The effect on our SFAS 87 and 106 costs and liabilities from changes in key assumptions are as follows: Increase in Costs from Adverse Changes in Key Assumptions ------------------------------------------------------------------------------ Assumption Adverse Change Pension OPEB Total - ------------------------------------------------------------------------------- (In millions) Discount rate................ Decrease by 0.25% $ 0.6 $0.6 $ 1.2 Long-term return on assets... Decrease by 0.25% $ 0.4 -- $ 0.4 Health care trend rate....... Increase by 1% na $1.6 $ 1.6 Increase in Minimum Liability ----------------------------- Discount rate................ Decrease by 0.25% $13.3 na $13.3 ------------------------------------------------------------------------------ As a result of the reduced market value of our pension plan assets, we were required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. We eliminated our prepaid pension asset of $57.2 million and established a minimum liability of $76.1 million, recording an intangible asset of $23.2 million and reducing OCI by $64.6 million (recording a related deferred tax benefit of $45.5 million). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002, increased due to the lower discount rate assumed and reduced market value of plan assets as of December 31, 2002. Our non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $9 million and $3 million, respectively - a total of $12 million in 2003 as compared to 2002. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset, is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- SFAS 143, "Accounting for Asset Retirement Obligations" In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143, "Accounting for Asset Retirement Obligations." The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize regulatory assets or liabilities if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. We have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $134 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $25 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144. No impairment was indicated. The asset retirement liability at the date of adoption was $298 million. As of December 31, 2002, the Companies had recorded decommissioning liabilities of $292 million, including unrealized gains on decommissioning trust funds of $11 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that substantially all nuclear decommissioning costs for Penn will be recoverable through its regulated rates. Therefore, Penn will recognize a regulatory liability of $69 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $23 million increase to income ($14 million net of tax). The $11 million of unrealized gains ($6 million net of tax) included in the decommissioning liability balances as of December 31, 2002, were offset against OCI upon adoption of SFAS 143. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities" This statement, which was issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time they are incurred rather than when management commits to a plan of exit or disposal. It also requires the use of fair value for the measurement of such liabilities. The new standard supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring)." This new standard was effective for exit and disposal activities initiated after December 31, 2002. Since it is applied prospectively, there will be no impact upon adoption. However, SFAS 146 could change the timing and amount of costs recognized in connection with future exit or disposal activities. FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. We currently have transactions with entities which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. We currently consolidate the majority of these entities and believe we will continue to consolidate following the adoption of FIN 46. In addition to the entities we are currently consolidating we believe that the PNBV Capital Trust, which was used to acquire a portion of the off-balance sheet debt issued in connection with the sale and leaseback of OE's interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require consolidation as a VIE under FIN 46. Ownership of the trust includes a three-percent equity interest by a nonaffiliated party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46 would change the characterization of the PNBV trust investment to a lease obligation bond investment. Also, consolidation of the outside minority interest would be required, which would increase assets and liabilities by $12.0 million.
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------ (In thousands) OPERATING REVENUES (Note 1J)............................................ $2,948,675 $3,056,464 $2,726,708 ---------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel and purchased power (Note 1J)................................... 986,737 1,096,317 418,790 Nuclear operating costs.............................................. 352,129 381,047 366,387 Other operating costs (Note 1J)...................................... 360,256 313,177 456,246 ---------- ---------- ---------- Total operation and maintenance expenses........................... 1,699,122 1,790,541 1,241,423 Provision for depreciation and amortization.......................... 370,830 424,920 578,679 General taxes........................................................ 177,021 153,506 225,849 Income taxes......................................................... 240,017 220,678 198,436 ---------- ---------- ---------- Total operating expenses and taxes................................. 2,486,990 2,589,645 2,244,387 ---------- ---------- ---------- OPERATING INCOME........................................................ 461,685 466,819 482,321 OTHER INCOME (Note 1J).................................................. 42,329 68,681 55,976 ---------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES...................................... 504,014 535,500 538,297 ---------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt........................................... 119,123 150,632 165,409 Allowance for borrowed funds used during construction and capitalized interest.............................. (3,639) (2,602) (9,523) Other interest expense............................................... 14,598 22,754 31,451 Subsidiaries' preferred stock dividend requirements.................. 10,449 14,504 14,504 ---------- ---------- ---------- Net interest charges............................................... 140,531 185,288 201,841 ---------- ---------- ---------- NET INCOME.............................................................. 363,483 350,212 336,456 PREFERRED STOCK DIVIDEND REQUIREMENTS................................... 6,510 10,702 11,124 ---------- ---------- ---------- EARNINGS ON COMMON STOCK................................................ $ 356,973 $ 339,510 $ 325,332 ========== ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------ (In thousands) ASSETS UTILITY PLANT: In service...................................................................... $4,989,056 $4,979,807 Less-Accumulated provision for depreciation..................................... 2,552,007 2,461,972 ---------- ---------- 2,437,049 2,517,835 ---------- ---------- Construction work in progress- Electric plant................................................................ 122,741 87,061 Nuclear Fuel.................................................................. 23,481 11,822 ---------- ---------- 146,222 98,883 ---------- ---------- 2,583,271 2,616,718 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: PNBV Capital Trust (Note 2)..................................................... 402,565 429,040 Letter of credit collateralization (Note 2)..................................... 277,763 277,763 Nuclear plant decommissioning trusts............................................ 293,190 277,337 Long-term notes receivable from associated companies (Note 3B).................. 503,827 505,028 Other (Note 1I)................................................................. 74,220 303,409 ---------- ---------- 1,551,565 1,792,577 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents....................................................... 20,512 4,588 Receivables- Customers (less accumulated provisions of $5,240,000 and $4,522,000, respectively, for uncollectible accounts)................................... 296,548 311,744 Associated companies.......................................................... 592,218 523,884 Other (less accumulated provision of $1,000,000 for uncollectible accounts at both dates)...................................................... 33,557 41,611 Notes receivable from associated companies...................................... 437,669 108,593 Materials and supplies, at average cost- Owned......................................................................... 58,022 53,900 Under consignment............................................................. 19,753 13,945 Prepayments and other........................................................... 11,804 50,541 ---------- ---------- 1,470,083 1,108,806 ---------- ---------- DEFERRED CHARGES: Regulatory assets............................................................... 2,012,754 2,234,227 Property taxes.................................................................. 59,035 58,244 Unamortized sale and leaseback costs............................................ 72,294 75,105 Other........................................................................... 51,739 30,276 ---------- ---------- 2,195,822 2,397,852 ---------- ---------- $7,800,741 $7,915,953 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity..................................................... $2,840,361 $2,671,001 Preferred stock not subject to mandatory redemption............................. 60,965 160,965 Preferred stock of consolidated subsidiary- Not subject to mandatory redemption........................................... 39,105 39,105 Subject to mandatory redemption............................................... 13,500 14,250 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures............... -- 120,000 Long-term debt.................................................................. 1,219,347 1,614,996 ---------- ---------- 4,173,278 4,620,317 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock............................ 563,267 576,962 Short-term borrowings (Note 4)- Associated companies.......................................................... 225,345 26,076 Other......................................................................... 182,317 219,750 Accounts payable- Associated companies.......................................................... 145,981 110,784 Other......................................................................... 18,015 19,819 Accrued taxes................................................................... 467,776 258,831 Accrued interest................................................................ 28,209 33,053 Other........................................................................... 73,882 63,140 ---------- ---------- 1,704,792 1,308,415 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes............................................... 1,016,680 1,175,395 Accumulated deferred investment tax credits..................................... 86,465 99,193 Nuclear plant decommissioning costs............................................. 292,353 276,500 Retirement benefits............................................................. 247,531 166,594 Other........................................................................... 279,642 269,539 ---------- ---------- 1,922,671 1,987,221 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 2 and 5)................................................................. ---------- ---------- $7,800,741 $7,915,953 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION As of December 31, 2002 2001 - --------------------------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, without par value, authorized 175,000,000 shares-100 shares outstanding ........ $2,098,729 $2,098,729 Accumulated other comprehensive loss (Note 3G)................................................ (65,713) -- Retained earnings (Note 3A)................................................................... 807,345 572,272 ---------- ---------- Total common stockholder's equity......................................................... 2,840,361 2,671,001 ---------- ---------- Number of Shares Optional Outstanding Redemption Price ------------------- -------------------- 2002 2001 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK (Note 3D): Cumulative, $100 par value- Authorized 6,000,000 shares Not Subject to Mandatory Redemption: 3.90%.................................. 152,510 152,510 $103.63 $15,804 15,251 15,251 4.40%.................................. 176,280 176,280 108.00 19,038 17,628 17,628 4.44%.................................. 136,560 136,560 103.50 14,134 13,656 13,656 4.56%.................................. 144,300 144,300 103.38 14,917 14,430 14,430 ------- --------- ------- ---------- ---------- 609,650 609,650 63,893 60,965 60,965 ------- --------- ------- ---------- ---------- Cumulative, $25 par value- Authorized 8,000,000 shares Not Subject to Mandatory Redemption: 7.75%.................................. -- 4,000,000 -- -- -- 100,000 ------- --------- ------- ---------- ---------- Total Not Subject to Mandatory Redemption......................... 609,650 4,609,650 $63,893 60,965 160,965 ======= ========= ======= ---------- ---------- PREFERRED STOCK OF CONSOLIDATED SUBSIDIARY (Note 3D): Pennsylvania Power Company- Cumulative, $100 par value- Authorized 1,200,000 shares Not Subject to Mandatory Redemption: 4.24%.................................. 40,000 40,000 $103.13 $ 4,125 4,000 4,000 4.25%.................................. 41,049 41,049 105.00 4,310 4,105 4,105 4.64%.................................. 60,000 60,000 102.98 6,179 6,000 6,000 7.75%.................................. 250,000 250,000 -- -- 25,000 25,000 ------- --------- ------- ---------- ---------- Total Not Subject to Mandatory Redemption......................... 391,049 391,049 $14,614 39,105 39,105 ======= ========= ======= ---------- ---------- Subject to Mandatory Redemption (Note 3E): 7.625%................................. 142,500 150,000 103.81 $14,793 14,250 15,000 Redemption Within One Year............. (750) (750) ------- --------- ------- ---------- ---------- Total Subject to Mandatory Redemption ........................ 142,500 150,000 $14,793 13,500 14,250 ======= ========= ======= ---------- ---------- COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES: Cumulative, $25 par value- Authorized 4,800,000 shares Subject to Mandatory Redemption: 9.00%.................................. -- 4,800,000 -- $ -- -- 120,000 ======= ========= ======= ---------- ----------
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd) As of December 31, 2002 2001 2002 2001 2002 2001 - --------------------------------------------------------------------------------------------------------------------------------- (In thousands) LONG-TERM DEBT (Note 3F): First mortgage bonds: Ohio Edison Company- Pennsylvania Power Company- 7.375% due 2002............... -- 120,000 9.740% due 2003-2019. 16,591 17,565 7.500% due 2002............... -- 34,265 7.500% due 2003...... 40,000 40,000 8.250% due 2002............... -- 125,000 6.375% due 2004...... 20,500 20,500 8.625% due 2003............... 150,000 150,000 6.625% due 2004...... 14,000 14,000 6.875% due 2005............... 80,000 80,000 8,500% due 2022...... 27,250 27,250 8.750% due 2022............... 50,960 50,960 7.625% due 2023...... 6,500 6,500 ------- ------- 7.625% due 2023............... 75,000 75,000 7.875% due 2023............... 93,500 93,500 ------- ------- Total first mortgage bonds......... 449,460 728,725 124,841 125,815 574,301 854,540 ------- ------- ------- ------- ---------- ---------- Secured notes: Ohio Edison Company- Pennsylvania Power Company- 7.930% due 2002............... -- 2,360 5.400% due 2013...... 1,000 1,000 7.680% due 2005............... 162,504 200,000 5.400% due 2017...... 10,600 10,600 *1.300% due 2015............... 19,000 19,000 *1.350% due 2017...... 17,925 17,925 6.750% due 2015............... 40,000 40,000 5.900% due 2018...... 16,800 16,800 7.050% due 2020............... 60,000 60,000 *1.350% due 2021...... 14,482 14,482 *1.350% due 2021............... 443 443 6.150% due 2023...... 12,700 12,700 5.375% due 2028............... 13,522 13,522 *1.600% due 2027...... 10,300 10,300 5.625% due 2029............... 50,000 50,000 6.450% due 2027...... -- 14,500 5.950% due 2029............... 56,212 56,212 5.375% due 2028...... 1,734 1,734 *1.300% due 2030............... 60,400 60,400 5.450% due 2028...... 6,950 6,950 *1.350% due 2031............... 69,500 69,500 6.000% due 2028...... 14,250 14,250 *1.350% due 2033............... 57,100 57,100 5.950% due 2029...... 238 238 ------- ------- 5.450% due 2033............... 14,800 14,800 Limited Partnerships-......... 7.41% weighted average........ interest rate due 2003-2010. 29,513 35,015 ------- ------- 632,994 678,352 106,979 121,479 739,973 799,831 ------- ------- ------- ------ ---------- ---------- OES Fuel- 2.72% weighted average interest as of December 31, 2001.................................................. -- 81,515 ---------- ---------- Total secured notes............................................................. 739,973 881,346 ---------- ---------- Unsecured notes: Ohio Edison Company- Pennsylvania Power Company- *1.500% due 2014............... 50,000 50,000 *5.900% due 2033...... 5,200 5,200 *4.850% due 2015............... 50,000 50,000 *3.850% due 2029...... 14,500 -- ------- ------- *5.800% due 2016............... 47,725 47,725 *1.750% due 2018............... 33,000 33,000 *1.750% due 2018............... 23,000 23,000 *1.600% due 2023............... 50,000 50,000 *4.300% due 2033............... 50,000 50,000 *4.650% due 2033............... 108,000 108,000 *4.400% due 2033............... 30,000 30,000 -------- -------- Total unsecured notes.............. 441,725 441,725 19,700 5,200 461,425 446,925 ------- ------- ------- ------- ---------- ---------- Capital lease obligations (Note 2)........................................................... 8,250 10,718 ---------- ---------- Net unamortized discount on debt............................................................. (2,085) (2,321) ---------- ---------- Long-term debt due within one year........................................................... (562,517) (576,212) ---------- ---------- Total long-term debt......................................................................... 1,219,347 1,614,996 ---------- ---------- TOTAL CAPITALIZATION......................................................................... $4,173,278 $4,620,317 ========== ========== * Denotes variable rate issue with December 31, 2002 interest rate shown. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Accumulated Other Comprehensive Number Carrying Comprehensive Retained Income of Shares Value Income (Loss) Earnings ------------- --------- ----- --------------- -------- (Dollars in thousands) Balance, January 1, 2000.................... 100 $2,098,729 $ -- $ 525,731 Net income............................... $336,456 336,456 ======== Cash dividends on preferred stock........ (11,124) Cash dividends on common stock........... (392,800) - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000.................. 100 2,098,729 -- 458,263 Net income............................... $350,212 350,212 ======== Cash dividends on preferred stock........ (10,703) Cash dividends on common stock........... (225,500) - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001.................. 100 2,098,729 -- 572,272 Net income............................... $363,483 363,483 Minimum liability for unfunded retirement benefits, net of $(45,525,000) of income taxes (64,585) (64,585) Unrealized loss on investments, net of $(794,000) of income taxes............. (1,128) (1,128) -------- Comprehensive income..................... $297,770 ======== Cash dividends on preferred stock........ (6,510) Cash dividends on common stock........... (121,900) - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002.................. 100 $2,098,729 $(65,713) $ 807,345 ====================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemption -------------------- -------------------- Number Par Number Par of Shares Value of Shares Value --------- ----- --------- ----- (Dollars in thousands) Balance, January 1, 2000......... 5,000,699 $ 200,070 5,050,000 $ 145,000 Redemptions- 8.45% Series................ (50,000) (5,000) ------------------------------------------------------------------------------------ Balance, December 31, 2000....... 5,000,699 200,070 5,000,000 140,000 Redemptions- 8.45% Series................ (50,000) (5,000) ------------------------------------------------------------------------------------ Balance, December 31, 2001....... 5,000,699 200,070 4,950,000 135,000 Redemptions - 7.75% Series................ (4,000,000) (100,000) 9.00% Series................ (4,800,000) (120,000) 7.625% Series................ (7,500) (750) ------------------------------------------------------------------------------------ Balance, December 31, 2002....... 1,000,699 $ 100,070 142,500 $ 14,250 ==================================================================================== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 - -------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income............................................................... $ 363,483 $ 350,212 $ 336,456 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization......................... 370,830 424,920 578,679 Nuclear fuel and lease amortization................................. 47,597 45,417 52,232 Deferred income taxes, net.......................................... (56,136) (63,945) (110,038) Investment tax credits, net......................................... (15,026) (13,346) (25,035) Receivables......................................................... (45,084) (61,246) (279,575) Materials and supplies.............................................. (9,930) 64,177 (7,625) Accounts payable.................................................... 182,229 (53,588) 70,089 Other (Note 7)...................................................... 219,238 (24,912) 8,753 ---------- --------- --------- Net cash provided from operating activities....................... 1,057,201 667,689 623,936 ---------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt........................................................ 14,500 111,584 207,283 Short-term borrowings, net............................................ 161,836 -- -- Redemptions and Repayments- Preferred stock....................................................... (220,750) (5,000) (5,000) Long-term debt........................................................ (425,742) (233,158) (485,178) Short-term borrowings, net............................................ -- (69,606) (42,864) Dividend Payments- Common stock.......................................................... (121,900) (225,500) (392,800) Preferred stock....................................................... (6,510) (10,703) (11,124) ---------- --------- --------- Net cash used for financing activities............................ (598,566) (432,383) (729,683) ---------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions....................................................... (148,967) (145,427) (279,508) Loans to associated companies............................................ (328,989) (262,076) (206,901) Loan payments from associated companies.................................. 1,113 1,032 -- Sale of assets to associated companies................................... -- 154,596 531,633 Other (Note 7)........................................................... 34,132 2,888 (8,383) ---------- --------- --------- Net cash provided from (used for) investing activities............ (442,711) (248,987) 36,841 ---------- --------- --------- Net increase (decrease) in cash and cash equivalents..................... 15,924 (13,681) (68,906) Cash and cash equivalents at beginning of year........................... 4,588 18,269 87,175 ---------- --------- --------- Cash and cash equivalents at end of year................................. $ 20,512 $ 4,588 $ 18,269 ========== ========= ========= SUPPLEMENTAL CASH FLOWS INFORMATION: Cash Paid During the Year- Interest (net of amounts capitalized)............................... $ 118,535 $ 180,263 $ 183,117 ========== ========= ========= Income taxes........................................................ $ 126,558 $ 240,882 $ 305,644 ========== ========= ========= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF TAXES For the Years Ended December 31, 2002 2001 2000 - ---------------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: Real and personal property............................................. $ 65,709 $ 45,132 $ 103,741 State gross receipts*.................................................. 18,516 45,271 104,851 Ohio kilowatt-hour excise*............................................. 85,762 55,795 -- Social security and unemployment....................................... 5,438 4,159 11,964 Other.................................................................. 1,596 3,149 5,293 ---------- ---------- ---------- Total general taxes............................................... $ 177,021 $ 153,506 $ 225,849 ========== ========== ========== PROVISION FOR INCOME TAXES: Currently payable- Federal............................................................. $ 281,598 $ 265,305 $ 329,616 State............................................................... 56,125 51,121 18,037 ---------- ---------- ---------- 337,723 316,426 347,653 ---------- ---------- ---------- Deferred, net- Federal............................................................. (36,411) (56,105) (102,692) State............................................................... (19,725) (7,840) (7,346) ---------- ---------- ---------- (56,136) (63,945) (110,038) ---------- ---------- ---------- Investment tax credit amortization..................................... (15,026) (13,346) (25,035) ---------- ---------- ---------- Total provision for income taxes.................................. $ 266,561 $ 239,135 $ 212,580 ========== ========== ========== INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating income....................................................... $ 240,017 $ 220,678 $ 198,436 Other income........................................................... 26,544 18,457 14,144 ---------- ---------- ---------- Total provision for income taxes.................................. $ 266,561 $ 239,135 $ 212,580 ========== ========== ========== RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes.......................... $ 630,044 $ 589,347 $ 549,036 ========== ========== ========== Federal income tax expense at statutory rate........................... $ 220,515 $ 206,271 $ 192,163 Increases (reductions) in taxes resulting from- Amortization of investment tax credits.............................. (15,026) (13,346) (25,035) State income taxes, net of federal income tax benefit............... 23,660 28,133 6,949 Amortization of tax regulatory assets............................... 28,671 32,020 39,746 Other, net.......................................................... 8,741 (13,943) (1,243) ---------- ---------- ---------- Total provision for income taxes.................................. $ 266,561 $ 239,135 $ 212,580 ========== ========== ========== ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences............................................. $ 397,930 $ 374,138 $ 377,521 Allowance for equity funds used during construction.................... 34,407 36,587 62,604 Competitive transition charge.......................................... 531,302 675,652 755,607 Customer receivables for future income taxes........................... 49,486 54,600 68,624 Deferred sale and leaseback costs...................................... (71,830) (77,099) (30,151) Unamortized investment tax credits..................................... (33,421) (38,680) (39,369) Deferred gain for asset sale to affiliated company..................... 70,812 85,311 73,312 Other comprehensive income............................................. (46,319) -- -- Other (Note 7)......................................................... 84,313 64,886 30,697 ---------- ---------- ---------- Net deferred income tax liability................................. $1,016,680 $1,175,395 $1,298,845 ========== ========== ========== * Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include Ohio Edison Company (Company) and its wholly owned subsidiaries. Pennsylvania Power Company (Penn) is the Company's principal operating subsidiary. All significant intercompany transactions have been eliminated. The Company is a wholly owned subsidiary of FirstEnergy Corp. FirstEnergy holds directly all of the issued and outstanding common shares of its principal electric utility operating subsidiaries, including, the Company and The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). JCP&L, Met-Ed and Penelec were formerly wholly owned subsidiaries of GPU, Inc. which merged with FirstEnergy on November 7, 2001. The Company and Penn (Companies) follow the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. (A) CONSOLIDATION- The Company consolidates all majority-owned subsidiaries, after eliminating the effects of intercompany transactions. Non-majority owned investments, including investments in limited liability companies, partnerships and joint ventures, are accounted for under the equity method when the Company is able to influence their financial or operating policies. Investments in corporations resulting in voting control of 20% or more are presumed to be equity method investments. Limited partnerships are evaluated in accordance with SEC Staff D-46, "Accounting for Limited Partnership Investments" and American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence. For all remaining investments (excluding those within the scope of Statement of Financial Accounting Standards (SFAS) 115, the Company applies the cost method. (B) REVENUES- The Companies' principal business is providing electric service to customers in central and northeastern Ohio and western Pennsylvania. The Companies' retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service through the end of the year. Receivables from customers include sales to residential, commercial and industrial customers located in the Companies' service area and sales to wholesale customers. There was no material concentration of receivables at December 31, 2002 or 2001, with respect to any particular segment of the Companies' customers. (C) REGULATORY PLANS- In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. In July 2000, the PUCO approved FirstEnergy's transition plan for the Company, CEI and TE as modified by a settlement agreement with major parties to the transition plan. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation" to the Company's generation business discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of the Company's generation-related transition costs as filed of $1.6 billion net of deferred income taxes and transition costs related to regulatory assets as filed of $1.0 billion net of deferred income taxes with recovery through no later than 2006 for the Company except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.0 billion, net of deferred income taxes of impaired generating assets recognized as regulatory assets as described further below and $1.2 billion, net of deferred income taxes of above market operating lease costs. Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 560 megawatts (MW) of generation capacity through 2005 at established prices for sales to the Company's retail customers. Customer prices are frozen through the five-year market development period except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Company was authorized increases in annual revenues aggregating approximately $41 million to recover its higher tax costs resulting from the Ohio deregulation legislation. The Company's customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be accomplished by extending the 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 period could have been shortened for the Company to reduce recovery by as much as $250 million. The Company achieved its required 20% customer shopping goals in 2002. Accordingly, the Company believes that there will be no regulatory action reducing the recoverable transition costs. Pennsylvania enacted its electric utility competition law in 1996 with the phase-in of customer choice for generation suppliers completed as of January 1, 2001. In 1998, the PPUC authorized a rate restructuring plan for Penn, which essentially resulted in the deregulation of Penn's generation business. The application of SFAS 71 has been discontinued with respect to the Companies' generation operations. The SEC issued interpretive guidance regarding asset impairment measurement concluding that any supplemental regulated cash flows such as a competitive transition charge (CTC) should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance, $1.2 billion of impaired plant investments were recognized by the Company as regulatory assets recoverable as transition costs through future regulatory cash flows and $227 million were recognized for Penn related to its 1998 impairment of its nuclear generating unit investments to be recovered through a CTC over a seven-year transition period. Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued, compared to the respective company's total assets as of December 31, 2002 were $947 million and $7.16 billion, respectively, for the Company and $82 million and $908 million, respectively, for Penn. (D) UTILITY PLANT AND DEPRECIATION- Utility plant reflects the original cost of construction (except for the Companies' nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs. The Companies' accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for the Company's electric plant was approximately 2.7% in 2002 and 2001, and 2.8% in 2000. The annual composite rate for Penn's electric plant was approximately 2.9% in 2002 and 2001, and 2.6% in 2000. Annual depreciation expense in 2002 included approximately $31.5 million for future decommissioning costs applicable to the Companies' ownership and leasehold interests in three nuclear generating units (Beaver Valley Units 1 and 2 and Perry Unit 1). The Companies' share of the future obligation to decommission these units is approximately $874 million in current dollars and (using a 4.0% escalation rate) approximately $1.9 billion in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Payments for decommissioning are expected to begin in 2016, when actual decommissioning work is expected to begin. The Companies have recovered approximately $160 million for decommissioning through their electric rates from customers through December 31, 2002. The Companies have also recognized an estimated liability of approximately $10.5 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy, as required by the Energy Policy Act of 1992. In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. The Companies have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143, asset retirement costs of $134 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $25 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets". No impairment was indicated. The asset retirement liability at the date of adoption will be $298 million. As of December 31, 2002, the Companies have recorded decommissioning liabilities of $292 million, including unrealized gains on decommissioning trust funds of $11 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that the ultimate nuclear decommissioning costs for Penn will be tracked and recovered through its regulated rates. Therefore, Penn recognized a regulatory liability of $69 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $23 million increase to income ($14 million net of tax). The $11 million of unrealized gains ($6 million net of tax), included in the decommissioning liability balances as of December 31, 2002 was offset against other comprehensive income (OCI) upon adoption of SFAS 143. (E) COMMON OWNERSHIP OF GENERATING FACILITIES- The Companies, together with CEI and TE, own and/or lease, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly owned facility in the same proportion as its interest. The Companies' portions of operating expenses associated with jointly owned facilities are included in the corresponding operating expenses on the Consolidated Statements of Income. The amounts reflected on the Consolidated Balance Sheet under utility plant at December 31, 2002 include the following:
Companies' Utility Accumulated Construction Ownership/ Plant Provision for Work in Leasehold Generating Units in Service Depreciation Progress Interest - --------------------------------------------------------------------------------------------------------------- (In millions) W. H. Sammis #7.............. $ 336.1 $ 165.3 $ -- 68.80% Bruce Mansfield #1, #2 and #3................. 987.6 534.1 3.4 67.18% Beaver Valley #1 and #2................. 64.8 14.8 67.7 77.81% Perry........................ 324.9 302.4 6.4 35.24% - --------------------------------------------------------------------------------------------------------------- Total..................... $1,713.4 $1,016.6 $77.5 ===============================================================================================================
(F) NUCLEAR FUEL- Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Companies amortize the cost of nuclear fuel based on the rate of consumption. (G) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 3c). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date resulting in substantially no intrinsic value. FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows: 2002 2001 2000 - ---------------------------------------------------------------------------- Valuation assumptions: Expected option term (years). 8.1 8.3 7.6 Expected volatility.......... 23.31% 23.45% 21.77% Expected dividend yield...... 4.36% 5.00% 6.68% Risk-free interest rate...... 4.60% 4.67% 5.28% Fair value per option.......... $6.45 $4.97 $2.86 - ---------------------------------------------------------------------------- The effects of applying fair value accounting to the Companies' stock options would not materially effect net income. (H) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. The Companies are included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Companies recognizing any tax losses or credits they contributed to the consolidated return. (I) RETIREMENT BENEFITS- FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all of the Companies' full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. On December 31, 2001, the GPU pension plans were merged with the FirstEnergy plan. The Companies use the projected unit credit method for funding purposes and were not required to make pension contributions during the three years ended December 31, 2002. The assets of the FirstEnergy pension plan consist primarily of common stocks, United States government bonds and corporate bonds. The Companies provide a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Companies pay insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Companies. The Companies recognize the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. As a result of the reduced market value of FirstEnergy's pension plan assets, it was required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. FirstEnergy's accumulated benefit obligation of $3.438 billion exceeded the fair value of plan assets ($2.889 billion) resulting in a minimum pension liability of $548.6 million. FirstEnergy eliminated its prepaid pension asset of $286.9 million (Companies - $57.2 million) and established a minimum liability of $548.6 million (Companies - - $76.1 million), recording an intangible asset of $78.5 million (Companies - $23.2 million) and reducing OCI by $444.2 million (Companies - $64.6 million) (recording a related deferred tax asset of $312.8 million (Companies - $45.5 million)). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002, increased due to the lower discount rate and asset returns assumed as of December 31, 2002. The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Other Pension Benefits Postretirement Benefits ---------------- ----------------------- 2002 2001 2002 2001 - -------------------------------------------------------------------------------------------------------- (In millions) Change in benefit obligation: Benefit obligation as of January 1............... $3,547.9 $1,506.1 $ 1,581.6 $ 752.0 Service cost..................................... 58.8 34.9 28.5 18.3 Interest cost.................................... 249.3 133.3 113.6 64.4 Plan amendments.................................. -- 3.6 (121.1) -- Actuarial loss................................... 268.0 123.1 440.4 73.3 Voluntary early retirement program............... -- -- -- 2.3 GPU acquisition.................................. (11.8) 1,878.3 110.0 716.9 Benefits paid.................................... (245.8) (131.4) (83.0) (45.6) ------------------------------------------------------------------------------------------------------- Benefit obligation as of December 31............. 3,866.4 3,547.9 2,070.0 1,581.6 ------------------------------------------------------------------------------------------------------- Change in fair value of plan assets: Fair value of plan assets as of January 1 3,483.7 1,706.0 535.0 23.0 Actual return on plan assets..................... (348.9) 8.1 (57.1) 12.7 Company contribution............................. -- -- 37.9 43.3 GPU acquisition.................................. -- 1,901.0 -- 462.0 Benefits paid.................................... (245.8) (131.4) (42.5) (6.0) ------------------------------------------------------------------------------------------------------- Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0 ------------------------------------------------------------------------------------------------------- Funded status of plan............................ (977.4) (64.2) (1,596.7) (1,046.6) Unrecognized actuarial loss...................... 1,185.8 222.8 751.6 212.8 Unrecognized prior service cost.................. 78.5 87.9 (106.8) 17.7 Unrecognized net transition obligation........... -- -- 92.4 101.6 ------------------------------------------------------------------------------------------------------- Net amount recognized............................ $ 286.9 $ 246.5 $ (859.5) $ (714.5) ======================================================================================================= Amounts recognized on the Consolidated Balance Sheets consist of: Prepaid (accrued) benefit cost................... $ (548.6) $ 246.5 $ (859.5) $ (714.5) Intangible asset................................. 78.5 -- -- -- Accumulated other comprehensive loss............. 757.0 -- -- -- ------------------------------------------------------------------------------------------------------- Net amount recognized............................ $ 286.9 $ 246.5 $ (859.5) $ (714.5) ======================================================================================================= Companies' share of net amount recognized..................................... $ 57.2 $ 210.7 $ (171.0) $ (165.8) ======================================================================================================= Assumptions used as of December 31: Discount rate.................................... 6.75% 7.25% 6.75% 7.25% Expected long-term return on plan assets......... 9.00% 10.25% 9.00% 10.25% Rate of compensation increase.................... 3.50% 4.00% 3.50% 4.00%
FirstEnergy's net pension and other postretirement benefit costs for the three years ended December 31, 2002 were computed as follows:
Other Pension Benefits Postretirement Benefits ------------------------ ------------------------- 2002 2001 2000 2002 2001 2000 ------------------------------------------------------------------------------------------------------ (In millions) Service cost........................... $ 58.8 $ 34.9 $ 27.4 $ 28.5 $18.3 $11.3 Interest cost.......................... 249.3 133.3 104.8 113.6 64.4 45.7 Expected return on plan assets......... (346.1) (204.8) (181.0) (51.7) (9.9) (0.5) Amortization of transition obligation.. (asset) .............................. -- (2.1) (7.9) 9.2 9.2 9.2 Amortization of prior service cost..... 9.3 8.8 5.7 3.2 3.2 3.2 Recognized net actuarial loss (gain)... -- -- (9.1) 11.2 4.9 -- Voluntary early retirement program..... -- 6.1 17.2 -- 2.3 -- ------------------------------------------------------------------------------------------------------ Net periodic benefit cost (income)..... $ (28.7) $ (23.8) $ (42.9) $114.0 $92.4 $68.9 ====================================================================================================== Companies' share of net benefit cost... $ 2.5 $ (3.2) $ (19.1) $ 14.8 $15.7 $24.7 ------------------------------------------------------------------------------------------------------
The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. (J) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily CEI, TE, ATSI, FirstEnergy Solutions Corp. (FES) and FirstEnergy Service Company (FECO). The Ohio transition plan, as discussed in the "Regulatory Plans" section, resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. Unregulated operations under FES now operate the generation businesses of the Companies, CEI and TE. As a result, the Companies entered into power supply agreements (PSA) whereby FES purchases all of the Companies' nuclear generation and the Companies purchase their power from FES to meet their "provider of last resort" obligations. The primary affiliated companies transactions, including the effects of the PSA beginning in 2001, the sale and leaseback of the Companies' transmission assets to ATSI in September 2000 and FECO's providing support services at cost, are as follows: 2002 2001 2000 - ---------------------------------------------------------------------------- (In millions) Operating Revenues: PSA revenues with FES............. $328.9 $ 355.9 $ -- Generating units rent with FES.... 178.4 178.8 -- Electric sales to CEI............. -- -- 53.4 Electric sales to TE.............. -- -- 15.9 Ground lease with ATSI............ 11.9 11.9 8.8 Operating Expenses: Purchased power under PSA......... 911.6 1,025.9 -- Transmission expense.............. 85.3 61.0 32.4 FirstEnergy support services...... 141.4 146.8 119.0 Other Income: Interest income from ATSI......... 15.9 16.0 5.4 Interest income from FES.......... 12.1 12.1 -- - ---------------------------------------------------------------------------- FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from its affiliates, GPU Service, Inc. and FirstEnergy Service Company, both subsidiaries of FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act (PUHCA). The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas: the ratio of each company's amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers and other factors; and specific departmental charge ratios. Management believes that these allocation methods are reasonable. (K) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Noncash financing and investing activities included capital lease transactions amounting to $1.3 million for the year 2000. There were no capital lease transactions in 2002 and 2001. Commercial paper transactions of OES Fuel, Incorporated (a wholly owned subsidiary of the Company) that had initial maturity periods of three months or less were reported net within financing activities under long-term debt, prior to the expiration of the related long-term financing agreement in March 2002, and were reflected as currently payable long-term debt on the Consolidated Balance Sheet as of December 31, 2001. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31:
2002 2001 - ---------------------------------------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value - ---------------------------------------------------------------------------------------------------- (In millions) Long-term debt................................. $1,776 $1,861 $2,101 $2,182 Preferred stock................................ $ 14 $ 14 $ 135 $ 138 Investments other than cash and cash equivalents: Debt securities: - Maturity (5-10 years)..................... $ 570 $ 539 $ 593 $ 562 - Maturity (more than 10 years)............. 458 532 461 514 Equity securities........................... 12 12 13 13 All other................................... 361 361 360 359 - ---------------------------------------------------------------------------------------------------- $1,401 $1,444 $1,427 $1,448 ====================================================================================================
The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Companies' ratings. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. The Companies have no securities held for trading purposes. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "All other" in the table above) consist of equity securities, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. In conjunction with the adoption of SFAS 143 on January 1, 2003, unrealized gains or losses were reclassified to OCI in accordance with SFAS 115. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized gains (losses) were approximately $(3.4) million and interest and dividend income totaled approximately $8.9 million. (L) REGULATORY ASSETS- The Companies recognize, as regulatory assets, costs which the FERC, PUCO and PPUC have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Companies' respective transition and rate restructuring plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations. The Companies recognized additional cost recovery of $270 million in 2000 as additional regulatory asset amortization in accordance with their prior Ohio and current Pennsylvania regulatory plans. The Companies recognized incremental transition cost recovery aggregating $274 million both in 2002 and in 2001 in accordance with the current Ohio transition plan and Pennsylvania restructuring plan. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2002 2001 - ------------------------------------------------------------------------------- (In millions) Regulatory transition costs..................... $1,847.6 $2,050.1 Customer receivables for future income taxes.... 127.2 139.5 Loss on reacquired debt......................... 28.0 30.3 Employee postretirement benefit costs........... 9.3 12.3 Other........................................... 0.7 2.0 - ------------------------------------------------------------------------------- Total.................................... $2,012.8 $2,234.2 =============================================================================== 2. LEASES The Companies lease certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. The Company sold portions of its ownership interest in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. During the terms of the leases, the Company continues to be responsible, to the extent of its individual combined ownership and leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company has the right, at the end of the respective basic lease terms, to renew the leases for up to two years. The Company also has the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes. OES Finance, Incorporated, a wholly owned subsidiary of the Company, maintains deposits pledged as collateral to secure reimbursement obligations relating to certain letters of credit supporting the Company's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits of approximately $278 million pledged to the financial institution providing those letters of credit are the sole property of OES Finance and are investments which are classified as "Held to Maturity." In the event of liquidation, OES Finance, as a separate corporate entity, would have to satisfy its obligations to creditors before any of its assets could be made available to the Company as sole owner of OES Finance common stock. Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2002, are summarized as follows: 2002 2001 2000 ------------------------------------------------------------------- (In millions) Operating leases Interest element......... $100.9 $102.7 $107.0 Other.................... 34.6 31.6 35.1 Capital leases Interest element......... 1.6 1.9 2.5 Other.................... 1.3 1.9 2.6 ------------------------------------------------------------------- Total rentals............ $138.4 $138.1 $147.2 =================================================================== The future minimum lease payments as of December 31, 2002, are:
Operating Leases ------------------------------------ Capital Lease PNBV Capital Leases Payments Trust Net --------------------------------------------------------------------------------------------- (In millions) 2003...................................... $ 2.9 $ 136.9 $ 62.9 $ 74.0 2004...................................... 4.4 137.8 58.5 79.3 2005...................................... 4.4 138.8 56.6 82.2 2006...................................... 4.4 139.9 59.6 80.3 2007...................................... 0.8 139.3 59.9 79.4 Years thereafter.......................... 3.4 1,272.6 356.4 916.2 --------------------------------------------------------------------------------------------- Total minimum lease payments.............. 20.3 $1,965.3 $653.9 $1,311.4 ======== ====== ======== Executory costs........................... 7.1 ------------------------------------------------- Net minimum lease payments................ 13.2 Interest portion.......................... 4.9 ------------------------------------------------- Present value of net minimum lease payments.......................... 8.3 Less current portion...................... 1.3 ------------------------------------------------- Noncurrent portion........................ $ 7.0 =================================================
The Company invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in the Company's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. The PNBV capital trust arrangement effectively reduces lease costs related to those transactions. 3. CAPITALIZATION: (A) RETAINED EARNINGS- Under the Company's first mortgage indenture, the Company's consolidated retained earnings unrestricted for payment of cash dividends on the Company's common stock were $803.4 million at December 31, 2002. (B) EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)- An ESOP Trust funds most of the matching contribution for FirstEnergy's 401(k) savings plan. All of the Companies' full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from the Company and acquired 10,654,114 shares of the Company's common stock (subsequently converted to FirstEnergy common stock) through market purchases. The ESOP loan is included in Other Property and Investments on the Consolidated Balance Sheets as of December 31, 2002 and 2001 as an investment with FirstEnergy related to the FirstEnergy savings plan. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. (C) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 2002 2001 2000 - ------------------------------------------------------------------------- Restricted common shares granted..... 36,922 133,162 208,400 Weighted average market price ....... $36.04 $35.68 $26.63 Weighted average vesting period (years) ........................... 3.2 3.7 3.8 Dividends restricted................. Yes * Yes ----------------------------------------------------------------------- * FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2002, there were 296,008 stock units outstanding. Stock option activities under the FE Programs for the past three years were as follows: Number of Weighted Average Stock Option Activities Options Exercise Price ---------------------------------------------------------------------------- Balance, January 1, 2000.............. 2,153,369 $25.32 (159,755 options exercisable)......... 24.87 Options granted..................... 3,011,584 23.24 Options exercised................... 90,491 26.00 Options forfeited................... 52,600 22.20 Balance, December 31, 2000........... 5,021,862 24.09 (473,314 options exercisable)......... 24.11 Options granted..................... 4,240,273 28.11 Options exercised................... 694,403 24.24 Options forfeited................... 120,044 28.07 Balance, December 31, 2001............ 8,447,688 26.04 (1,828,341 options exercisable)....... 24.83 Options granted..................... 3,399,579 34.48 Options exercised................... 1,018,852 23.56 Options forfeited................... 392,929 28.19 Balance, December 31, 2002........... 10,435,486 28.95 (1,400,206 options exercisable)....... 26.07 As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 1G - "Stock-Based Compensation." (D) PREFERRED AND PREFERENCE STOCK- Penn's 7.75% series of preferred stock has a restriction which prevents early redemption prior to July 2003. All other preferred stock may be redeemed by the Companies in whole, or in part, with 30-60 days' notice. The Company has eight million authorized and unissued shares of preference stock having no par value. (E) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- Penn's 7.625% series has an annual sinking fund requirement for 7,500 shares. The Companies' preferred shares are retired at $100 per share plus accrued dividends. Annual sinking fund requirements are approximately $750,000 in each year 2003 through 2006 and $11.25 million in 2007. (F) LONG-TERM DEBT- Each of the Companies has a first mortgage indenture under which it issues from time to time first mortgage bonds secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. The Companies have various debt covenants under their respective financing arrangements. The most restrictive of their debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Companies. Based on the amount of bonds authenticated by the respective mortgage bond trustees through December 31, 2002, the Companies' annual improvement fund requirements for all bonds issued under the various mortgage indentures of the Companies amounts to $39.3 million. The Companies expect to deposit funds with their respective mortgage bond trustees in 2003 that will then be withdrawn upon the surrender for cancellation of a like principal amount of bonds, specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) ---------------------------------------------- 2003................................. $561.2 2004................................. 258.3 2005................................. 136.8 2006................................. 5.6 2007................................. 5.8 ---------------------------------------------- Included in the table above are amounts for various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. These amounts are $311 million and $161 million in 2003 and 2004, respectively, which represents the next date at which the debt holders may exercise this provision. The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $171.5 million and noncancelable municipal bond insurance policies of $238.9 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letters of credit or policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.375% of the amounts of the letters of credit to the issuing banks and are obligated to reimburse the banks for any drawings thereunder. (G) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with FirstEnergy. As of December 31, 2002, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $(64.6) million and unrealized losses on investments in securities available for sale of $(1.1) million. 4. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT: Short-term borrowings outstanding as of December 31, 2002, consisted of $22.6 million of bank borrowings and $159.7 million of OES Capital, Incorporated commercial paper. OES Capital is a wholly owned subsidiary of the Company whose borrowings are secured by customer accounts receivable. OES Capital can borrow up to $170 million under a receivables financing agreement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.20% on the amount of the entire finance limit. The receivables financing agreement expires in August 2003. As of December 31, 2002, the Company also had total short-term borrowings of $225.3 million from its affiliates. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2002 and 2001, were 1.63% and 2.45%, respectively. The Company has lines of credit with domestic banks that provide for borrowings of up to $34 million under various interest rate options. Short-term borrowings may be made under these lines of credit on its unsecured notes. To assure the availability of these lines, the Company is required to pay annual commitment fees of 0.20%. These lines expire at various times during 2003. 5. COMMITMENTS AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Companies' current forecast reflects expenditures of approximately $391 million for property additions and improvements from 2003-2007, of which approximately $139 million is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $97 million, of which approximately $42 million applies to 2003. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $85 million and $41 million, respectively, as the nuclear fuel is consumed. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on their ownership and leasehold interests in the Beaver Valley Station and the Perry Plant, the Companies' maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $168.1 million per incident but not more than $19.1 million in any one year for each incident. The Companies are also insured as to their respective interests in Beaver Valley and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Companies have also obtained approximately $537 million of insurance coverage for replacement power costs for their respective interests in Beaver Valley and Perry. Under these policies, the Companies can be assessed a maximum of approximately $31.6 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Companies intend to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies' plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs. (C) ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. In accordance with the Ohio transition plan discussed in "Regulatory Plans" in Note 1, generation operations and any related additional capital expenditures for environmental compliance are the responsibility of FirstEnergy's competitive services business unit. The Companies are required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The 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 oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. 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. 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 the Companies 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 require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of these proceedings, the Companies believe the Sammis Plant is in full compliance with the Clean Air Act and the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. 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 effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on the Companies' earnings and competitive position. These environmental regulations affect the Companies' earnings and competitive position to the extent they compete with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. The Companies believe they are in material compliance with existing regulations but are unable to predict whether environmental regulations will change and what, if any, the effects of such change would be. (D) LEGAL MATTERS- Various lawsuits, claims and proceedings related to the Companies' normal business operations are pending against FirstEnergy and its subsidiaries. The most significant applicable to the Companies are described above. 6. RECENTLY ISSUED ACCOUNTING STANDARDS: FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions beginning in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. The Company currently has transactions with an entity in connection with a sale and leaseback arrangement which fall within the scope of this interpretation and which is reasonably possible of meeting the definition of a VIE in accordance with FIN 46. The Company currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. In addition to the entities the Company is currently consolidating the Company believes that the PNBV Capital Trust, which was used to acquire a portion of the off-balance sheet debt issued in connection with the sale and leaseback of OE's interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require consolidation. Ownership of the trust includes a three-percent equity interest by a nonaffiliated party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of the Company. Full consolidation of the trust under FIN 46 would change the characterization of the PNBV trust investment to a lease obligation bond investment. Also, consolidation of the outside minority interest would be required, which would increase assets and liabilities by $12.0 million. 7. OTHER INFORMATION: The following financial data provides supplemental unaudited information to the consolidated financial statements previously reported in 2001 and 2000: (A) Consolidated Statements of Cash Flows 2002 2001 2000 ---- ---- ---- (In Thousands) Other Cash Flows From Operating Activities: Accrued taxes........................... $208,945 $ 26,606 $24,863 Accrued interest........................ (4,844) (1,053) (3,466) Prepayments and other................... 38,737 26,393 (3,252) All other............................... (23,600) (76,858) (9,392) ------------------------------------------------------------------------------ Total-Other........................... $219,238 $(24,912) $ 8,753 ============================================================================== Other Cash Flows from Investing Activities: Retirements and transfers............... $ 7,476 $ 15,528 $(6,854) Nuclear decommissioning trust investments ........................... (15,688) (15,816) (8,879) Other investments....................... 18,820 3,209 -- All other............................... 23,524 (33) 7,350 ------------------------------------------------------------------------------ Total-Other........................... $ 34,132 $ 2,888 $(8,383) ============================================================================== (B) Consolidated Statements of Taxes 2002 2001 2000 ---- ---- ---- (In Thousands) Other Accumulated Deferred Income Taxes at December 31: Retirement Benefits..................... $ 20,969 $ 24,591 $30,896 All other............................... 63,344 40,295 (199) - ------------------------------------------------------------------------------- Total-Other........................... $ 84,313 $ 64,886 $30,697 ============================================================================== 8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
March 31, June 30, September 30, December 31, Three Months Ended 2002 2002 2002 2002 - ------------------------------------------------------------------------------------------------------ (In millions) Operating Revenues.................. $707.8 $744.5 $813.3 $683.1 Operating Expenses and Taxes........ 610.7 605.9 658.8 611.6 - ------------------------------------------------------------------------------------------------------ Operating Income.................... 97.1 138.6 154.5 71.5 Other Income........................ 0.5 15.1 14.2 12.5 Net Interest Charges................ 41.2 35.9 33.7 29.7 - ------------------------------------------------------------------------------------------------------ Net Income.......................... $ 56.4 $117.8 $135.0 $ 54.3 ====================================================================================================== Earnings on Common Stock............ $ 53.8 $115.2 $134.4 $ 53.6 ====================================================================================================== March 31, June 30, September 30, December 31, Three Months Ended 2001 2001 2001 2001 - ------------------------------------------------------------------------------------------------------ (In millions) Operating Revenues.................. $783.1 $744.7 $815.7 $712.9 Operating Expenses and Taxes........ 694.3 606.8 693.2 595.3 - ------------------------------------------------------------------------------------------------------ Operating Income.................... 88.8 137.9 122.5 117.6 Other Income........................ 12.4 17.8 18.7 19.8 Net Interest Charges................ 47.0 50.5 45.0 42.8 - ------------------------------------------------------------------------------------------------------ Net Income.......................... $ 54.2 $105.2 $ 96.2 $ 94.6 ====================================================================================================== Earnings on Common Stock............ $ 51.5 $102.5 $ 93.5 $ 92.0 ======================================================================================================
Report of Independent Accountants To the Stockholders and Board of Directors of Ohio Edison Company: In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of Ohio Edison Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The consolidated financial statements of Ohio Edison Company and subsidiaries as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financials statements in their report dated March 18, 2002. PricewaterhouseCoopers LLP Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. Report of Independent Public Accountants To the Stockholders and Board of Directors of Ohio Edison Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Ohio Edison Company (an Ohio corporation and wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Ohio Edison Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. EX-21 16 oe_ex21-1.txt EX. 21.1 LIST OF SUBS - OE EXHIBIT 21.1 OHIO EDISON COMPANY LIST OF SUBSIDIARIES OF THE REGISTRANT AT DECEMBER 31, 2002 Pennsylvania Power Company - Incorporated in Pennsylvania OES Ventures, Incorporated - Incorporated in Ohio OES Capital, Incorporated - Incorporated in Delaware OES Finance, Incorporated - Incorporated in Ohio OES Nuclear, Incorporated - Incorporated in Ohio Ohio Edison Financing Trust - Incorporated in Delaware Ohio Edison Financing Trust II - Incorporated in Delaware Statement of Differences ------------------------ Exhibit Number 21, List of Subsidiaries of the Registrant at December 31, 2002, is not included in the printed document. EX-23 17 oe_ex23-1.txt EX. 23-1 PWC CONSENT - OE EXHIBIT 23.1 OHIO EDISON COMPANY CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 33-49135, 33-49259, 33-49413, 33-51139, 333-01489 and 333-05277) of Ohio Edison Company of our report dated February 28, 2003 relating to the consolidated financial statements, which appears in the Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 28, 2003 relating to the financial statement schedule, which appears in this Form 10-K. PricewaterhouseCoopers LLP Cleveland, Ohio March 24, 2003 EX-4 18 cei_ex4-1.txt EX. 4-1 SUPPLEMENTAL INDENTURE (83RD) CEI ======================================================================== THE CLEVELAND ELECTRIC ILLUMINATING COMPANY TO JPMORGAN CHASE BANK (formerly known as THE CHASE MANHATTAN BANK) (successor to Morgan Guaranty Trust Company of New York, formerly Guaranty Trust Company of New York) As Trustee under The Cleveland Electric Illuminating Company's Mortgage and Deed of Trust, Dated July 1, 1940 ------------------ Eighty-third Supplemental Indenture DATED AS OF May 15, 2002 First Mortgage Bonds, 2002 Series A ======================================================================== Eighty-third Supplemental Indenture, dated as of May 15, 2002, made by and between THE CLEVELAND ELECTRIC ILLUMINATING COMPANY, a corporation organized and existing under the laws of the State of Ohio (the "Company"), and JPMORGAN CHASE BANK (formerly known as THE CHASE MANHATTAN BANK) (successor to MORGAN GUARANTY TRUST COMPANY OF NEW YORK), a corporation organized and existing under the laws of the State of New York (the "Trustee"), as Trustee under the Mortgage and Deed of Trust dated July 1, 1940, hereinafter mentioned: RECITALS In order to secure First Mortgage Bonds of the Company ("Bonds"), the Company has heretofore executed and delivered to the Trustee the Mortgage and Deed of Trust dated July 1, 1940 (the "1940 Mortgage") and 82 Supplemental Indentures thereto ("Supplemental Indentures"); and The 1940 Mortgage, as supplemented and modified by said Supplemental Indentures and by this Eighty-third Supplemental Indenture, will be hereinafter collectively referred to as the "Indenture" and this Eighty-third Supplemental Indenture will be hereinafter referred to as "this Supplemental Indenture"; and The Indenture provides among other things that the Company, from time to time, in addition to the Bonds authorized to be executed, authenticated and delivered pursuant to other provisions therein, may execute and deliver additional Bonds to the Trustee and the Trustee shall thereupon authenticate and deliver such Bonds to or upon the order of the Company; and The Company has determined to create pursuant to the provisions of the Indenture a new series of Bonds designated as "First Mortgage Bonds, 2002 Series A" (the "Bonds of 2002 Series A"), with the denominations, rates of interest, dates of maturity, redemption provisions and other provisions and agreements in respect thereof as in this Supplemental Indenture set forth; and The Company, in the exercise of the powers and authority conferred upon and reserved to it under the provisions of the Indenture, and pursuant to appropriate resolutions of the Board of Directors, has duly resolved and determined to make, execute and deliver to the Trustee this Supplemental Indenture in the form hereof for the purposes herein provided; and All conditions and requirements necessary to make this Supplemental Indenture a valid, binding and legal instrument have been done, performed and fulfilled and the execution and delivery hereof have been in all respects duly authorized. Now, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH: That The Cleveland Electric Illuminating Company, in consideration of the premises and of the mutual covenants herein contained and of the sum of One Dollar ($1.00) to it duly paid by the Trustee at or before the ensealing and delivery of these presents and for other valuable considerations, the receipt whereof is hereby acknowledged, hereby covenants and agrees to and with the Trustee and its successors in the Trust under the Indenture, for the benefit of those who shall hold the Bonds and coupons, if any, issued and to be issued thereunder and under this Supplemental Indenture as hereinafter provided, as follows: Article I CONFIRMATION OF 1940 MORTGAGE AND SUPPLEMENTAL INDENTURES The 1940 Mortgage (as modified in Article V of the Supplemental Indenture dated December 1, 1947, Article V of the Supplemental Indenture dated May 1, 1954, Article V of the Supplemental Indenture dated March 1, 1958, Article V of the Supplemental Indenture dated January 15, 1969, Article III of the Supplemental Indenture dated November 23, 1976, Article III of the Supplemental Indenture dated April 15, 1985 and Article II of the Supplemental Indenture dated as of June 30, 1999) and the Supplemental Indentures dated July 1, 1940, August 18, 1944, December 1, 1947, September 1, 1950, June 1, 1951, May 1, 1954, March 1, 1958, April 1, 1959, December 20, 1967, January 15, 1969, November 1, 1969, June 1, 1970, November 15, 1970, May 1, 1974, April 15, 1975, April 16, 1975, May 28, 1975, February 1, 1976, November 23, 1976, July 26, 1977, September 27, 1977, May 1, 1978, September 1, 1979, April 1, 1980, April 15, 1980, May 28, 1980, June 9, 1980, December 1, 1980, July 28, 1981, August 1, 1981, March 1, 1982, July 15, 1982 , September 1, 1982, November 1, 1982, November 15, 1982, May 24, 1983, May 1, 1984, May 23, 1984, June 27, 1984, September 4, 1984, November 14, 1984, November 15, 1984, April 15, 1985, May 28, 1985, August 1, 1985, September 1, 1985, November 1, 1985, April 15, 1986, May 14, 1986, May 15, 1986, February 25, 1987, October 15, 1987, February 24, 1988, September 15, 1988, May 15, 1989, June 13, 1989, October 15, 1989, January 1, 1990, June 1, 1990, August 1, 1990, May 1, 1991, May 1, 1992, July 31, 1992, January 1, 1993, February 1, 1993, May 20, 1993, June 1, 1993, September 15, 1994, May 1, 1995, May 2, 1995, June 1, 1995, July 15, 1995, August 1, 1995, June 15, 1997, August 1, 1997, October 15, 1997, June 1, 1998, October 1, 1998, October 1, 1998, April 1, 1999, June 30, 1999 and January 15, 2000 respectively, are hereby in all respects confirmed. Article II CREATION, PROVISIONS, REDEMPTION, PRINCIPAL AMOUNT AND FORM OF BONDS OF 2002 SERIES A Section 1. The Company hereby creates a new series of Bonds to be authenticated and delivered under and secured by the Indenture and to be designated as "First Mortgage Bonds, 2002 Series A" of the Company and hereinabove and hereinafter called the "Bonds of 2002 Series A". The Bonds of 2002 Series A shall be limited to an aggregate principal amount of $358,500,000.00. The Bonds of 2002 Series A shall be executed, authenticated and delivered in accordance with the provisions of, and shall in all respect be subjected to, all of the terms, conditions and covenants of the Indenture. Section 2. The Bonds of 2002 Series A shall be dated the date of authentication, shall mature on May 15, 2003 and shall bear interest as stated in the form of the Bonds of 2002 Series A hereinafter set forth. Section 3. The Bonds of 2002 Series A shall be payable, both as to principal and interest, at the offices of the Company, 76 South Main Street, Akron, Ohio 44308; and shall be payable in any coin or currency of the Untied States of America which at the time of payment shall be legal tender for the payment of public and private debts. Section 4. The Bonds of 2002 Series A shall be issued only as one fully registered Bond in the denomination of $358,500,000. Section 5. In the manner and subject to the limitations provided in the Indenture and this Supplemental Indenture, the Bonds of 2002 Series A may be transferred on the books of the Company without charge, except for any tax or taxes or other governmental charges incident to such transfer. Section 6. The Bonds of 2002 Series A shall be redeemable as provided in the form of the Bonds of 2002 Series A hereinafter set forth. Section 7. The form of the fully registered Bonds of 2002 Series A and of the Trustee's certificate of authentication thereon, shall be substantially as follows: [FORM OF FULLY REGISTERED BOND OF 2002 SERIES A] THE BONDS OF 2002 SERIES A HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933 AND MAY BE SOLD OR TRANSFERRED ONLY IF SO REGISTERED OR IF AN EXEMPTION FROM REGISTRATION IS AVAILABLE. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY Incorporated under the laws of the State of Ohio FIRST MORTGAGE BOND, 2002 SERIES A No. $ THE CLEVELAND ELECTRIC ILLUMINATING COMPANY, a company organized and existing under the laws of the State of Ohio (hereinafter called the "Company", which term shall include any successor corporation as defined in the Indenture hereinafter referred to), for value received, hereby promises to pay to, or registered assigns, the sum of ______________ Dollars ($____________) together with interest thereon at the rate of 4.925% per annum, on May 15, 2003, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. The interest hereon shall accrue from the date of original issuance hereof until maturity, or, in case the Bonds of 2002 Series A (as hereinafter defined) are duly called for redemption in accordance with the second succeeding paragraph, until the redemption date, or, in the case of any default by the Company in the payment of the principal due on the Bonds of 2002 Series A, until the Company's obligation with respect to the payment of the principal hereof shall be discharged as provided in the Indenture hereinafter referred to. Interest hereon shall be payable only at maturity or on said redemption date and in each case shall be payable to the person to whom principal is payable. This Bond is one of the duly authorized Bonds of the Company (herein called the "Bonds"), all equally secured by a Mortgage and Deed of Trust dated July 1, 1940, executed by the Company to Guaranty Trust Company of New York as Trustee under which JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank) is successor trustee (herein called the "Trustee"), and all indentures supplemental thereto (said Mortgage as so supplemented herein called the "Indenture") to which reference is hereby made for a description of the properties mortgaged and pledged, the nature and extent of the security, the rights of the registered owner or owners of the Bonds and of the trustee in respect thereof and the terms and conditions upon which the Bonds are, and are to be, secured. The Bonds may be issued in series, for various principal sums, may mature at different times, may bear interest at different rates and may otherwise vary as in the Indenture provided. This Bond is the only Bond of a series designated as the First Mortgage Bonds, 2002 Series A (herein called the "Bonds of 2002 Series A") limited in aggregate principal amount to $358,500,000.00 and secured by the Indenture and described in the Eighty-third Supplemental Indenture dated as of May 15, 2002, between the Company and the trustee (herein called the "Supplemental Indenture"). The Bonds of 2002 Series A are subject to redemption prior to maturity, in whole but not in part, at the option of either the Company or the registered owner thereof, upon notice given to the other party not less than one day prior to the date selected for redemption, at a price equal to 100% of the principal amount thereof, together with accrued interest thereon. To the extent permitted by and as provided in the Indenture, modifications or alterations of the Indenture, or of any indenture supplemental thereto, and of the rights and obligations of the Company and of the holders of the Bonds and coupons may be made with the consent of the Company by an affirmative vote of not less than 60% in principal amount of the Bonds entitled to vote then outstanding, at a meeting of Bondholders called and held as provided in the Indenture, and, in case one or more but less than all of the series of Bonds then outstanding under the Indenture are so affected, by an affirmative vote of not less than 60% in principal amount of the Bonds of any series entitled to vote then outstanding and affected by such modification or alternation; provided, however, that no such modification or alternation shall be made which will affect the terms of payment on this Bond. Pursuant to the Nineteenth Supplemental Indenture dated November 23, 1976 between the Company and the Trustee, the Company has reserved the right to modify the Indenture to except and exclude nuclear fuel (to the extent, if any, not otherwise excepted and excluded) from the lien and operation thereof without any vote, consent or other action by the holders of Bonds. If an event of default, as defined in the Indenture, shall occur, the principal of all the Bonds at any such time outstanding under the Indenture may be declared or may become due and payable, upon the conditions and in the manner and with the effect provided in the Indenture. The Indenture provides that such declaration may in certain events be waived by the holders of a majority in principal amount of the Bonds outstanding. No recourse shall be had for the payment on this Bond, or for any claim based hereon or on the Indenture or any indenture supplemental thereto, against any incorporator, or against any stockholder, director or officer, past, present or future, of the Company, or of any predecessor or successor corporation, as such, either directly or through the Company or any such predecessor or successor corporation, whether by virtue of any constitution, statute or rule of law, or by the enforcement of any assessment or penalty or otherwise, all such liability, whether at common law, in equity, by any constitution or statute or otherwise, of incorporators, stockholders, directors or officers being released by every owner hereof by the acceptance of this Bond and as part of the consideration for the issue hereof, and being likewise released by the terms of the Indenture. This Bond shall not be entitled to any benefit under the Indenture or any indenture supplement thereto, or become valid or obligatory for any purpose, until the Trustee under the Indenture, or a successor trustee thereto under the Indenture, shall have signed the form of certificate of authentication endorsed hereon. IN WITNESS WHEREOF, The Cleveland Electric Illuminating Company has cause this Bond to be signed in its name by its President or a Vice President and its corporate seal to be hereto affixed and attested by its Corporate Secretary or an Assistant Corporate Secretary. Dated: THE CLEVELAND ELECTRIC ILLUMINATING COMPANY By:__________________________________ Vice President ATTEST: By:____________________ Corporate Secretary [FORM OF TRUSTEE'S CERTIFICATE OF AUTHENTICATION] This Bond is one of the Bonds of the series designated and described in the within-mentioned Indenture and Supplemental Indenture. JPMORGAN CHASE BANK Trustee By:_________________________________ Authorized Officer [END FORM OF FULLY REGISTERED BOND OF 2002 SERIES A] Article III THE TRUSTEE Section 1. The Trustee hereby accepts the trusts hereby declared and provided upon the terms and conditions in the Indenture set forth and upon the terms and conditions set forth in this Article III. Section 2. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or the due execution hereof by the Company or for or in respect of the recitals contained herein, all of which recitals are made by the Company solely. In general, each and every term and condition contained in Article XIII of the Indenture shall apply to this Supplemental Indenture with the same force and effect as if the same were herein set forth in full, with such omissions, variations and modifications thereof as may be appropriate. Article IV MISCELLANEOUS PROVISIONS This Supplemental Indenture may be executed in any number of counterparts, each of which when so executed shall be deemed to be an original; but such counterparts shall together constitute but one and the same instrument. EXECUTION IN WITNESS WHEREOF, said The Cleveland Electric Illuminating Company has caused this Supplemental Indenture to be executed on its behalf by its President or one of its Vice Presidents and its corporate seal to be hereto affixed and said seal and this Supplemental Indenture to be attested by its Corporate Secretary or an Assistant Corporate Secretary, and said JPMorgan Chase Bank, in evidence of its acceptance of the trust hereby created, has caused this Supplemental Indenture to be executed on its behalf by one of its Vice Presidents or one of its Trust Officers and its corporate seal to be hereto affixed and said seal and this Supplemental Indenture to be attested by one of its Assistant Trust Officers or Assistant Secretaries, all as of the day and year first above written. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY By:__________________________________ Senior Vice President ATTEST:____________________ Corporate Secretary Signed, sealed and acknowledged by The Cleveland Electric Illuminating Company in the present of - ----------------------------- Matthew R. Wushinske - ----------------------------- Nadine M. Stith As witnesses JPMORGAN CHASE BANK By:__________________________________ Attest:____________________ Signed, sealed and acknowledged by JPMorgan Chase Bank In the present of - ----------------------------- - ----------------------------- As witnesses STATE OF OHIO ) )SS.: COUNTY OF SUMMIT ) On this 29th day of May, 2002, before me personally appeared Richard H. Marsh and Nancy C. Ashcom to me personally known, who being by me severally duly sworn, did say that they are a Senior Vice President and Corporate Secretary, respective, of The Cleveland Electric Illuminating Company, that the seal affixed to the foregoing instrument is the corporate seal of said corporation and that said instrument was signed and sealed in behalf of said corporation by authority of its Board of Directors; and said officers severally acknowledged said instrument to be the free act and deed of said corporation. ------------------------------------- Susie M. Hoisten, Notary Public Residence - Summit County State Wide Jurisdiction, Ohio My Commission Expires December 9, 2006 STATE OF NEW YORK ) ) SS.: COUNTY OF NEW YORK ) On this 29th day of May, 2002, before me personally appeared _____________ and __________________ to me personally known, who being by me severally duly sworn, did say that they are a _______________ and _________________, respective, of JPMorgan Chase Bank, that the seal affixed to the foregoing instrument is the corporate seal of said corporation and that said instrument was signed and sealed in behalf of said corporation by authority of its Board of Directors; and said officers severally acknowledged said instrument to be the free act and deed of said corporation. --------------------------------- Notary Public Notary Public, State of New York This Instrument Prepared by FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308 EX-4 19 cei_ex4-2.txt EX. 4-2 SUPPLEMENTAL INDENTURE =============================================================================== THE CLEVELAND ELECTRIC ILLUMINATING COMPANY TO JPMORGAN CHASE BANK (formerly known as THE CHASE MANHATTAN BANK), (successor to Morgan Guaranty Trust Company of New York, formerly Guaranty Trust Company of New York) as Trustee under The Cleveland Electric Illuminating Company's Mortgage and Deed of Trust, Dated July 1, 1940 Eighty-fourth Supplemental Indenture Dated as of October 1, 2002 First Mortgage Bonds, Pledge Series A of 2002 due 2033 =============================================================================== Eighty-fourth Supplemental Indenture, dated as of October 1, 2002, made by and between THE CLEVELAND ELECTRIC ILLUMINATING COMPANY, a corporation organized and existing under the laws of the State of Ohio (the "Company"), and JPMORGAN CHASE BANK (formerly known as THE CHASE MANHATTAN BANK), successor by merger to The Chase Manhattan Bank (National Association), which in turn was successor to Morgan Guaranty Trust Company of New York, formerly Guaranty Trust Company of New York), a corporation organized and existing under the laws of the State of New York (the "Trustee"), as Trustee under the Mortgage and Deed of Trust dated July 1, 1940, hereinafter mentioned: RECITALS In order to secure First Mortgage Bonds of the Company ("Bonds"), the Company has heretofore executed and delivered to the Trustee the Mortgage and Deed of Trust dated July 1, 1940 (the "1940 Mortgage") and eighty-three Supplemental Indentures thereto; and The 1940 Mortgage, as supplemented and modified by said Supplemental Indentures and by this Eighty-fourth Supplemental Indenture, will be hereinafter collectively referred to as the "Indenture" and this Eighty-fourth Supplemental Indenture will be hereinafter referred to as "this Supplemental Indenture"; and The Indenture provides among other things that the Company, from time to time, in addition to the Bonds authorized to be executed, authenticated and delivered pursuant to other provisions therein, may execute and deliver additional Bonds to the Trustee and the Trustee shall thereupon authenticate and deliver such Bonds to or upon the order of the Company; and The Company has determined to create pursuant to the provisions of the Indenture one new series of first mortgage bonds (the "Series A Bonds"), with such first mortgage bonds to have the denominations, rates of interest, date of maturity, redemption provisions and other provisions and agreements in respect thereof as in this Supplemental Indenture set forth; and The Series A Bonds are to be limited in aggregate principal amount to $30,000,000 and are to be issued by the Company and delivered to Ambac Assurance Corporation, a Wisconsin-domiciled stock insurance corporation (the "Insurer") pursuant to an Insurance Agreement, dated as of October 1, 2002 (the "Insurance Agreement"), between the Company and the Insurer under which (i) the Insurer has agreed to issue a municipal bond insurance policy (the "Policy") insuring the payment of the principal of and interest on, and for the benefit of the holders of, $30,000,000 aggregate principal amount of the State of Ohio Pollution Control Revenue Refunding Bonds, Series 2002-B (The Cleveland Electric Illuminating Company Project) (the "Authority Bonds") to be issued by the Ohio Air Quality Development Authority (the "Authority") and (ii) the Company has agreed to deliver to the Insurer a series of its first mortgage bonds as security for the Company's obligation to reimburse the Insurer in respect of payments made by the Insurer under the Policy; and The Company, in the exercise of the powers and authority conferred upon and reserved to it under the provisions of the Indenture, and pursuant to appropriate resolutions of its Board of Directors, has duly resolved and determined to make, execute and deliver to the Trustee this Supplemental Indenture in the form hereof for the purposes herein provided; and 2 All conditions and requirements necessary to make this Supplemental Indenture a valid, binding and legal instrument have been done, performed and fulfilled and the execution and delivery hereof have been in all respects duly authorized. NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH: That The Cleveland Electric Illuminating Company, in consideration of the premises and of the mutual covenants herein contained and of the sum of One Dollar ($1.00) to it duly paid by the Trustee at or before the ensealing and delivery of these presents and for other valuable considerations, the receipt whereof is hereby acknowledged, hereby covenants and agrees to and with the Trustee and its successors in the Trust under the Indenture, for the benefit of those who shall hold the Bonds and coupons, if any, issued and to be issued thereunder and under this Supplemental Indenture as hereinafter provided, as follows: ARTICLE I CONFIRMATION OF 1940 MORTGAGE AND SUPPLEMENTAL INDENTUREs ------------------------------------ The 1940 Mortgage (as modified in Article V of the Supplemental Indenture dated December 1, 1947, Article V of the Supplemental Indenture dated May 1, 1954, Article V of the Supplemental Indenture dated March 1, 1958, Article V of the Supplemental Indenture dated January 15, 1969, Article III of the Supplemental Indenture dated November 23, 1976 and Article III of the Supplemental Indenture dated April 15, 1985) and the Supplemental Indentures dated July 1, 1940, August 18, 1944, December 1, 1947, September 1, 1950, June 1, 1951, May 1, 1954, March 1, 1958, April 1, 1959, December 20, 1967, January 15, 1969, November 1, 1969, June 1, 1970, November 15, 1970, May 1, 1974, April 15, 1975, April 16, 1975, May 28, 1975, February 1, 1976, November 23, 1976, July 26, 1977, September 27, 1977, May 1, 1978, September 1, 1979, April 1, 1980, April 15, 1980, May 28, 1980, June 9, 1980, December 1, 1980, July 28, 1981, August 1, 1981, March 1, 1982, July 15, 1982, September 1, 1982, November 1, 1982, November 15, 1982, May 24, 1983, May 1, 1984, May 23, 1984, June 27, 1984, September 4, 1984, November 14, 1984, November 15, 1984, April 15, 1985, May 28, 1985, August 1, 1985, September 1, 1985, November 1, 1985, April 15, 1986, May 14, 1986, May 15, 1986, February 25, 1987, October 15, 1987, February 24, 1988, September 15, 1988, May 15, 1989, June 13, 1989, October 15, 1989, January 1, 1990, June 1, 1990, August 1, 1990, May 1, 1991, May 1, 1992, July 31, 1992, January 1, 1993, February 1, 1993, May 20, 1993, June 1, 1993, September 15, 1994, May 1, 1995, May 2, 1995, June 1, 1995, July 15, 1995, August 1, 1995, June 15, 1997, August 1, 1997, October 15, 1997, June 1, 1998 and October 1, 1998, October 1, 1998, April 1, 1999, June 30, 1999, January 15, 2000 and May 15, 2002, respectively, are hereby in all respects confirmed. 3 ARTICLE II creation, PROVISIONS, REDEMPTION, PRINCIPAL AMOUNT AND FORM OF SERIES A BONDS ------------------------------------------- Section 2.01 The Company hereby creates a new series of Bonds to be issued under and secured by the Indenture and to be designated as "First Mortgage Bonds, Pledge Series A of 2002 due 2033" of the Company and hereinabove and hereinafter called the "Series A Bonds." The Series A Bonds shall be executed, authenticated and delivered in accordance with the provisions of, and shall in all respects be subject to, all of the terms, conditions and covenants of the Indenture. Section 2.02 The Series A Bonds shall be issued as fully registered Bonds only, without coupons, in the denominations of $1,000 and any integral multiple thereof. Section 2.03 The Series A Bonds shall be dated the date of authentication, shall mature on September 1, 2033, and shall bear interest from the time hereinafter provided at such rate per annum on each interest payment date (hereinafter defined) as shall cause the amount of interest payable on each interest payment date on such Series A Bonds to equal the amount of interest payable on such interest payment date on the Authority Bonds. Such interest shall be payable on the same dates as interest is payable on the Authority Bonds (each such date hereinafter called an "interest payment date"), on and until maturity, or, in the case of any such Series A Bonds duly called for redemption, on and until the redemption date, or in the case of any default by the Company in the payment of the principal due on any such Series A Bonds, until the Company's obligation with respect to the payment of the principal shall be discharged as provided in the Indenture. The amount of interest payable on each interest payment date shall be computed on the same basis as the corresponding amount is computed on the Authority Bonds, provided, however, that the aggregate amount of interest payable on any interest payment date shall not exceed an amount which results in an interest rate of more than 10% per annum on the aggregate principal amount of the Series A Bonds outstanding from time to time. The Series A Bonds shall be payable as to principal and interest at the agency of the Company in the Borough of Manhattan, The City of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Except as hereinafter provided, each Series A Bond shall bear interest (a) from the interest payment date next preceding the date of such Series A Bond to which interest has been paid, or (b) if the date of such Series A Bond is an interest payment date to which interest has been paid, then from such date, or (c) if no interest has been paid thereon, then from the date of initial issue. The Trustee may rely upon the certification of the Insurer of the interest rate of, interest payment dates of and basis on which interest is computed for, the Authority Bonds as necessary to enable the Trustee to determine for the Series A Bonds their corresponding interest rate, interest payment dates and basis on which interest shall be computed and with respect to its payments under the Policy. 4 The interest payable on any interest payment date shall be paid to the respective persons in whose names the Series A Bonds shall be registered on such interest payment date. If any interest payment date should fall on a day that is not a business day, then such interest payment date shall be the next succeeding business day. Section 2.04 In the manner and subject to the limitations provided in the Indenture, Series A Bonds may be exchanged for a like aggregate principal amount of Series A Bonds of other authorized denominations, in either case without charge, except for any tax or taxes or other governmental charges incident to such transfer or exchange, at the office or agency of the Company in the Borough of Manhattan, The City of New York or the City of Akron, State of Ohio. The Company, the agencies of the Company and the Trustee may deem and treat the person in whose name a Series A Bond is registered as the absolute owner thereof for the purpose of receiving any payment and for all other purposes. Section 2.05 The Series A Bonds shall be redeemable only to the extent provided in this Article II, subject to the provisions contained in Article VI of the Indenture and the form of Series A Bond. Section 2.06 Subject to the applicable provisions of the Indenture, written notice of redemption of Series A Bonds pursuant to this Supplemental Indenture shall be given by the Trustee by mailing to each registered owner of such Series A Bonds to be redeemed a notice of such redemption, first class postage prepaid, at its last address as it shall appear upon the books of the Company for the registration and transfer of such Series A Bonds. Any notice of redemption shall be mailed at least thirty (30) days, but no more than sixty (60) days, prior to the redemption date. Section 2.07 The Series A Bonds shall be redeemed by the Company in whole or in part at any time prior to maturity at a redemption price of 100% of the principal amount to be redeemed, plus accrued and unpaid interest to the redemption date, as stated in the form of the Series A Bonds hereinafter set forth. The Series A Bonds shall not otherwise be subject to redemption by the Company prior to maturity. Section 2.08 The Company's obligation to pay the principal of or interest on the Series A Bonds, shall be fully or partially satisfied as stated in the form of the Series A Bonds hereinafter set forth. Section 2.09 Series A Bonds shall not be transferable except to a successor to the Insurer under the Insurance Agreement or as may be necessary to comply with a final order of a court of competent jurisdiction in connection with any bankruptcy or reorganization proceeding of the Company. Section 2.10 The aggregate principal amount of Series A Bonds which may be authenticated and delivered hereunder shall not exceed $30,000,000, except as otherwise provided in the Indenture. 5 Section 2.11 The form of the fully registered Series A Bonds, and of the Trustee's certificate of authentication thereon, shall be substantially as follows: [FORM OF FULLY REGISTERED BOND] THIS BOND IS NOT TRANSFERABLE EXCEPT TO A SUCCESSOR TO AMBAC ASSURANCE CORPORATION (THE "INSURER") UNDER THE INSURANCE AGREEMENT, DATED AS OF OCTOBER 1, 2002, BETWEEN THE COMPANY AND AMBAC ASSURANCE CORPORATION, AS AMENDED OR SUPPLEMENTED (THE "INSURANCE AGREEMENT"), OR IN COMPLIANCE WITH A FINAL ORDER OF A COURT OF COMPETENT JURISDICTION IN CONNECTION WITH ANY BANKRUPTCY OR REORGANIZATION PROCEEDING OF THE COMPANY. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY Incorporated under the laws of the State of Ohio FIRST MORTGAGE BOND, PLEDGE SERIES A OF 2002 DUE 2033 No. $___________ THE CLEVELAND ELECTRIC ILLUMINATING COMPANY, a corporation organized and existing under the laws of the State of Ohio (hereinafter called the "Company," which term shall include any successor corporation as defined in the Indenture hereinafter referred to), for value received, hereby promises to pay to _________________________________, or registered assigns, the principal sum of _______________________ dollars ($_________) or the aggregate unpaid principal amount hereof, whichever is less, on September 1, 2033, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts, and to pay interest on the unpaid principal amount hereof in like coin or currency at such rate per annum on each interest payment date (hereinafter defined) as shall cause the amount of interest payable on such interest payment date on the Pledge Bonds (hereinafter defined) to equal the amount of interest payable on such interest payment date on the Authority Bonds (hereinafter defined). Such interest shall be payable on the same dates as interest is payable on said Authority Bonds (each such date hereinafter called an "interest payment date"), until maturity or redemption of this Bond, or, if the Company shall default in the payment of the principal due on this Bond, until the Company's obligation with respect to the payment of such principal shall be discharged as provided in the Indenture (hereinafter defined). The amount of interest payable on each interest payment date shall be computed on the same basis as the corresponding amount is computed on the Authority Bonds, provided, however, that the aggregate amount of interest payable on any interest payment date shall not exceed an amount which results in an interest rate of more than 10% per annum on the aggregate principal amount of the Pledge Bonds outstanding from time to time. 6 Except as hereinafter provided, this Bond shall bear interest (a) from the interest payment date next preceding the date of this Bond to which interest has been paid, or (b) if the date of this Bond is an interest payment date to which interest has been paid, then from such date, or (c) if no interest has been paid on this Bond, then from the date of initial issue. Subject to certain exceptions provided in said Indenture, the interest payable on any interest payment date shall be paid to the person in whose name this Bond shall be registered on such date. Principal of and interest on this Bond are payable at the agency of the Company in the Borough of Manhattan, The City of New York or the City of Akron, State of Ohio. This Bond is one of the duly authorized Bonds of the Company (herein called the "Bonds"), all issued and to be issued under and equally secured by a Mortgage and Deed of Trust dated July 1, 1940, executed by the Company to Guaranty Trust Company of New York (subsequently Morgan Guaranty Trust Company of New York and then The Chase Manhattan Bank (National Association)), now succeeded by JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank), as Trustee (herein called the "Trustee"), and all indentures supplemental thereto (said Mortgage as so supplemented herein called the "Indenture") to which reference is hereby made for a description of the properties mortgaged and pledged, the nature and extent of the security, the rights of the registered owner or owners of the Bonds and of the Trustee in respect thereof, and the terms and conditions upon which the Bonds are, and are to be, secured. The Bonds may be issued in series, for various principal sums, may mature at different times, may bear interest at different rates and may otherwise vary as in the Indenture provided. This Bond is one of a series designated as the First Mortgage Bonds, Pledge Series A of 2002 due 2033 (herein called the "Pledge Bonds") limited, except as otherwise provided in the Indenture, in aggregate principal amount to $30,000,000, issued under and secured by the Indenture and described in the Eighty-fourth Supplemental Indenture dated as of October 1, 2002, between the Company and the Trustee (herein called the "Supplemental Indenture"). The Pledge Bonds have been issued by the Company to Ambac Assurance Corporation, a Wisconsin-domiciled stock insurance corporation (the "Insurer"), to (i) provide for the payment of the Company's obligations to make payments to the Insurer under an Insurance Agreement, dated as of October 1, 2002 (the "Insurance Agreement"), between the Company and the Insurer, and (ii) provide to the Insurer the benefits of the security provided for the Pledge Bonds. The Insurance Agreement has been entered into by the Company in connection with the issuance by the Insurer of a municipal bond insurance policy (the "Policy") insuring the payment of the principal of and interest on, and for the benefit of the holders of, $30,000,000 aggregate principal amount of the State of Ohio Pollution Control Revenue Refunding Bonds, Series 2002-B (The Cleveland Electric Illuminating Company Project) (the "Authority Bonds") issued on behalf of the Company by the Ohio Air Quality Development Authority (the "Authority") and under the Trust Indenture, dated as of October 1, 2002 (the "Authority Bond Indenture"), between the Authority and The Bank of New York, as trustee (such trustee and any successor trustee being hereinafter referred to as the "Authority Bond Trustee"). Payments made by the Company of principal and interest on the Pledge Bonds are intended to be sufficient to reimburse the Insurer for any payments of principal and interest made by the Insurer on the Authority Bonds pursuant to the Policy. 7 The Pledge Bonds are not transferable except (i) as required to effect an assignment to a successor of the Insurer under the Insurance Agreement or (ii) in compliance with a final order of a court of competent jurisdiction in connection with any bankruptcy or reorganization proceeding of the Company. The Company's obligation to make payments with respect to the principal of and/or interest on the Pledge Bonds shall be fully or partially satisfied and discharged to the extent that, at the time any such payment shall be due, the corresponding amount then due of principal of and/or interest on the Authority Bonds shall have been fully or partially paid (other than by the application of the proceeds of any payment by the Insurer under the Policy), as the case may be, or there shall have been deposited with the Authority Bond Trustee pursuant to the Authority Bond Indenture trust funds sufficient to fully or partially pay, as the case may be, the corresponding amount then due of principal of and/or interest on the Authority Bonds (other than by the application of the proceeds of any payment by the Insurer under the Policy). Notwithstanding anything contained herein or in the Indenture to the contrary, the Company shall be obligated to make payments with respect to the principal of and/or interest on the Pledge Bonds only to the extent that the Insurer has made a payment with respect to the Authority Bonds under the Policy. Upon payment of the principal of and interest due on the Authority Bonds, whether at maturity or prior to maturity by acceleration, redemption or otherwise, or upon provision for the payment thereof having been made in accordance with the Authority Bond Indenture (other than by the application of the proceeds of any payment by the Insurer under the Policy), the Pledge Bonds in a principal amount equal to the principal amount of Authority Bonds so paid or for which such provision for payment has been made shall be deemed fully paid, satisfied and discharged and the obligations of the Company thereunder shall be terminated and such Pledge Bonds shall be surrendered to and canceled by the Trustee. From and after the Release Date (as defined in the Insurance Agreement), the Pledge Bonds shall be deemed fully paid, satisfied and discharged and the obligation of the Company thereunder shall be terminated. On the Release Date, the Pledge Bonds shall be surrendered to and canceled by the Trustee. The Pledge Bonds are subject to mandatory redemption, in whole or in part, as the case may be, on each date that Authority Bonds are to be redeemed. The principal amount of the Pledge Bonds to be redeemed on any such date shall be equal to the principal amount of Authority Bonds called for redemption on that date. All redemptions of Pledge Bonds shall be at 100% of the principal amount thereof, plus accrued interest to the redemption date. In the Forty-third Supplemental Indenture dated April 15, 1985 between the Company and the Trustee, the Company has modified, in certain respects, the redemption provisions in the Indenture effective only with respect to the Bonds of all series established or created in said Forty-third Supplemental Indenture and all supplemental indentures dated after May 28, 1985. To the extent permitted by and as provided in the Indenture, modifications or alterations of the Indenture, or of any indenture supplemental thereto, and of the rights and obligations of the Company and of the holders of the Bonds and coupons may be made with the consent of the Company by an affirmative vote of not less than 60% in principal amount of the Bonds entitled to vote then outstanding, at a meeting of Bondholders called and held as provided in the 8 Indenture, and, in case one or more but less than all of the series of Bonds then outstanding under the Indenture are so affected, by an affirmative vote of not less than 60% in principal amount of the Bonds of any series entitled to vote then outstanding and affected by such modification or alteration; provided, however, that no such modification or alteration shall be made which will affect the terms of payment of the principal of or interest on this Bond. Pursuant to the Nineteenth Supplemental Indenture dated November 23, 1976 between the Company and the Trustee, the Company has reserved the right to modify the Indenture to except and exclude nuclear fuel (to the extent, if any, not otherwise excepted and excluded) from the lien and operation thereof without any vote, consent or other action by the holders of Bonds. If an event of default, as defined in the Indenture, shall occur, the principal of all the Bonds at any such time outstanding under the Indenture may be declared or may become due and payable, upon the conditions and in the manner and with the effect provided in the Indenture. The Indenture provides that such declaration may in certain events be waived by the holders of a majority in principal amount of the Bonds outstanding. Subject to the limitations provided herein and in the Indenture and Section 2.09 of the Supplemental Indenture, this Bond is transferable by the registered owner hereof, in person or by duly authorized attorney, on the books of the Company to be kept for that purpose at the office or agency of the Company in the Borough of Manhattan, The City of New York or the City of Akron, State of Ohio upon surrender and cancellation of this Bond, and upon presentation of a duly executed written instrument of transfer, and thereupon new fully registered Pledge Bonds of the same series, of the same aggregate principal amount and in authorized denominations will be issued to the transferee or transferees in exchange herefor, and this Bond, with or without others of the same series, may in like manner be exchanged for one or more new fully registered Pledge Bonds of the same series of other authorized denominations but of the same aggregate principal amount; all without charge except for any tax or taxes or other governmental charges incidental to such transfer or exchange and all subject to the terms and conditions set forth in the Indenture. The Company, the agencies of the Company and the Trustee may deem and treat the person in whose name this Bond is registered as the absolute owner hereof for the purpose of receiving any payment and for all other purposes. No recourse shall be had for the payment of the principal of or the interest on this Bond, or for any claim based hereon or on the Indenture or any indenture supplemental thereto, against any incorporator, or against any stockholder, director or officer, past, present or future, of the Company, or of any predecessor or successor corporation, as such, either directly or through the Company or any such predecessor or successor corporation, whether by virtue of any constitution, statute or rule of law, or by the enforcement of any assessment or penalty or otherwise, all such liability, whether at common law, in equity, by any constitution or statute or otherwise, of incorporators, stockholders, directors or officers being released by every owner hereof by the acceptance of this Bond and as part of the consideration for the issue hereof, and being likewise released by the terms of the Indenture. This Bond shall not be entitled to any benefit under the Indenture or any indenture supplemental thereto, or become valid or obligatory for any purpose, until the Trustee under the Indenture, or a successor trustee thereto under the Indenture, shall have signed the form of certificate of authentication endorsed hereon. 9 IN WITNESS WHEREOF, The Cleveland Electric Illuminating Company has caused this Bond to be signed in its name by its President or a Vice President (whose signature may be manual or a facsimile thereof) and its corporate seal (or a facsimile thereof) to be hereto affixed and attested by its Corporate Secretary or an Assistant Secretary (whose signature may be manual or a facsimile thereof). Dated: THE CLEVELAND ELECTRIC ILLUMINATING COMPANY Attest: By: ______________________________________ Vice President - -------------------------------- Corporate Secretary [FORM OF TRUSTEE'S CERTIFICATE OF AUTHENTICATION] This Bond is one of the Bonds of the series designated and described in the within-mentioned Indenture and Supplemental Indenture. JP MORGAN CHASE BANK, TRUSTEE By: ------------------------------------ Authorized Officer [END OF FORM OF FULLY REGISTERED BOND] 10 ARTICLE III THE TRUSTEE ----------- Section 3.01 The Trustee hereby accepts the trusts hereby declared and provided upon the terms and conditions in the Indenture set forth and upon the terms and conditions set forth in this Article III. Section 3.02 The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or the due execution hereof by the Company or for or in respect of the recitals contained herein, all of which recitals are made by the Company solely. In general, each and every term and condition contained in Article XIII of the Indenture shall apply to this Supplemental Indenture with the same force and effect as if the same were herein set forth in full, with such omissions, variations and modifications thereof as may be appropriate. Section 3.03 For purposes of this Supplemental Indenture (a) the Trustee may conclusively rely and shall be protected in acting upon the written demand from, or certificate of, any agency duly appointed by resolution of the Board of Directors of the Company or any officer's certificate or opinion of counsel, as to the truth of the statements and the correctness of the opinions expressed therein, without independent investigation or verification thereof, subject to Article XIII of the Indenture and (b) a written demand from, or certificate of, an agency of the Company shall mean a written demand or certificate executed by the president, any vice president or any trust officer of, or any other person authorized to act for, such agency, as such. Section 3.04 The Company shall cause any agency of the Company, other than the Trustee, which it may appoint from time to time to act as such agency in respect of the Pledge Bonds, to execute and deliver to the Trustee an instrument in which such agency shall: (a) Agree to keep and maintain, and furnish to the Trustee from time to time as reasonably requested by the Trustee, appropriate records of all transactions carried out by it as such agency and to furnish the Trustee such other information and reports as the Trustee may reasonably require; (b) Certify that it is eligible for appointment as such agency and agree to notify the Trustee promptly if it shall cease to be so eligible; and (c) Agree to indemnify the Trustee, in a manner satisfactory to the Trustee, against any loss, liability or expense incurred by, and defend any claim asserted against, the Trustee by reason of any acts or failures to act as such agency, except for any liability resulting from any action taken by it at the specific direction of the Trustee; provided, however, that the Company, in lieu of causing any such agency to furnish such an instrument, may make such other arrangements with the Trustee in respect of any such agency as shall be satisfactory to the Trustee. 11 Section 3.05 For purposes of this Supplemental Indenture (a) the Trustee may conclusively rely and shall be protected in acting upon a written certificate of the Insurer as to the interest rate of, interest payment dates of and basis on which interest is computed for, the Authority Bonds and with respect to payments under the Authority Bonds, its payments under the Policy and the occurrence of the Release Date, or any officer's certificate or opinion of counsel, as to the truth of the statements and the correctness of the opinions expressed therein, without independent investigation or verification thereof, subject to Article XIII of the Indenture, (b) a written certificate of the Insurer shall mean a written certificate executed by the president, any vice president or any authorized officer of the Insurer and (c) in the absence of a written certificate of the Insurer with respect to its payments under the Policy, the Trustee may conclusively assume that no such payments have been made. ARTICLE IV MISCELLANEOUS PROVISIONS ------------------------ This Supplemental Indenture may be executed in any number of counterparts, each of which when so executed shall be deemed to be an original, but such counterparts shall together constitute but one and the same instrument. 12 EXECUTION IN WITNESS WHEREOF, said The Cleveland Electric Illuminating Company has caused this Supplemental Indenture to be executed on its behalf by its President or one of its Vice Presidents and its corporate seal to be hereto affixed and said seal and this Supplemental Indenture to be attested by its Corporate Secretary or an Assistant Secretary, and said JPMorgan Chase Bank, in evidence of its acceptance of the trust hereby created, has caused this Supplemental Indenture to be executed on its behalf by one of its Vice Presidents or one of its Trust Officers, and its corporate seal to be hereto affixed and said seal and this Supplemental Indenture to be attested by one of its Secretaries or authorized officers, all as of the day and year first above written. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY By: -------------------------------------------------------------------- Richard H. Marsh, Senior Vice President and Chief Financial Officer [SEAL] Attest: - ------------------------------------- Nancy C. Ashcom, Corporate Secretary Signed, sealed and acknowledged by The Cleveland Electric Illuminating Company in the presence of - ---------------------------------- Michael J. Sulhan - ---------------------------------- Julie A. Phillips As Witnesses 13 JPMORGAN CHASE BANK, AS TRUSTEE By: ------------------------------------------------- ____________________, Vice President Attest: - -------------------------------------- ________________, Trust Officer Signed, sealed and acknowledged by JPMorgan Chase Bank in the presence of - ----------------------------------- Print Name: - ----------------------------------- Print Name: As witnesses 14 STATE OF OHIO ) : ss.: COUNTY OF SUMMIT ) On this 8th day of October 2002, before me personally appeared Richard H. Marsh and Nancy C. Ashcom, to me personally known, who being by me severally duly sworn, did say that they are a Senior Vice President and Chief Financial Officer and the Corporate Secretary, respectively, of The Cleveland Electric Illuminating Company, that the seal affixed to the foregoing instrument is the corporate seal of said corporation and that said instrument was signed and sealed in behalf of said corporation by authority of its Board of Directors; and said officers severally acknowledged said instrument to the free act and deed of said corporation. --------------------------------------- Notary Public Susie M. Hoisten Residence - Summit County State Wide Jurisdiction, Ohio My Commission expires December 9, 2006 STATE OF NEW YORK) : ss.: COUNTY OF NEW YORK) On this 8th day of October, 2002, before me personally appeared ________________ and ____________________, to me personally known, who being by me severally duly sworn, did say that they are a Vice President and a Trust Officer, respectively, of JPMorgan Chase Bank, that the seal affixed to the foregoing instrument is the corporate seal of said corporation and that said instrument was signed and sealed in behalf of said corporation by authority of its Board of Directors; and said officers severally acknowledged said instrument to the free act and deed of said corporation. --------------------------------------------- Notary Public, State of New York No. ______________ Qualified in ______ County Certificate Filed in ________ County Commission Expires ______________ This instrument prepared by: FirstEnergy Corp., 76 South Main Street, Akron, Ohio 44308. EX-12 20 cei_ex12-3.txt EX. 12-3 FIXED CHARGE RATIO - CEI EXHIBIT 12.3 Page 1 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
Year Ended December 31, ----------------------------------------------------------- 1998 1999 2000 2001 2002 ---- ---- ---- ---- ---- Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items........................ $164,891 $194,089 $202,950 $219,044 $155,946 Interest and other charges, before reduction for amounts capitalized.................................... 232,727 211,960 202,752 192,198 189,502 Provision for income taxes............................... 110,611 123,869 126,701 158,648 101,844 Interest element of rentals charged to income (a)........ 68,314 66,680 65,616 59,497 51,170 -------- -------- -------- -------- -------- Earnings as defined.................................... $576,543 $596,598 $598,019 $629,387 $498,462 ======== ======== ======== ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K: Interest expense......................................... $232,727 $211,960 $202,752 $192,198 180,602 Subsidiary's, preferred stock dividend requirements...... -- -- -- -- 8,900 Interest element of rentals charged to income (a)........ 68,314 66,680 65,616 59,497 51,170 -------- -------- -------- -------- -------- Fixed charges as defined............................... $301,041 $278,640 $268,368 $251,695 $240,672 ======== ======== ======== ======== ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES............. 1.92 2.14 2.23 2.50 2.07 ==== ==== ==== ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
EXHIBIT 12.3 Page 2 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
Year Ended December 31, ----------------------------------------------------------- 1998 1999 2000 2001 2002 ---------- --------- ---------- --------- -------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items................................. $164,891 $194,089 $202,950 $219,044 $155,946 Interest and other charges, before reduction for amounts capitalized..................................................... 232,727 211,960 202,752 192,198 189,502 Provision for income taxes........................................ 110,611 123,869 126,701 158,648 101,844 Interest element of rentals charged to income (a)................. 68,314 66,680 65,616 59,497 51,170 -------- -------- -------- -------- -------- Earnings as defined............................................. $576,543 $596,598 $598,019 $629,387 $498,462 ======== ======== ======== ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS): Interest expense.................................................. $232,727 $211,960 $202,752 $192,198 $180,602 Preferred stock dividend requirements............................. 24,794 33,524 20,843 25,838 26,290 Adjustments to preferred stock dividends to state on a pre-income tax basis.............................. 16,632 21,395 13,012 18,714 17,169 Interest element of rentals charged to income (a)................. 68,314 66,680 65,616 59,497 51,170 -------- -------- -------- -------- -------- Fixed charges as defined plus preferred stock dividend requirements (pre-income tax basis).................. $342,467 $333,559 $302,223 $296,247 $275,231 ======== ======== ======== ======== ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)............................................ 1.68 1.79 1.98 2.12 1.81 ==== ==== ==== ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
EX-13 21 cei_ex13-2.txt EX. 13-2 ANNUAL REPORT - CEI THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 2002 ANNUAL REPORT TO STOCKHOLDERS The Cleveland Electric Illuminating Company (CEI) is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the generation, distribution and sale of electric energy in an area of approximately 1,700 square miles in northeastern Ohio. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 1.9 million. Contents Page - -------- ---- Selected Financial Data......................................... 1 Management's Discussion and Analysis............................ 2-12 Consolidated Statements of Income............................... 13 Consolidated Balance Sheets..................................... 14 Consolidated Statements of Capitalization....................... 15-16 Consolidated Statements of Common Stockholder's Equity.......... 17 Consolidated Statements of Preferred Stock...................... 17 Consolidated Statements of Cash Flows........................... 18 Consolidated Statements of Taxes................................ 19 Notes to Consolidated Financial Statements...................... 20-33 Reports of Independent Accountants.............................. 34-35
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY SELECTED FINANCIAL DATA 2002 2001 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- (Dollars in thousands) GENERAL FINANCIAL INFORMATION: Operating Revenues...................... $1,835,371 $2,076,222 $1,887,039 $1,864,954 $1,795,997 ========== ========== ========== ========== ========== Operating Income........................ $ 325,146 $ 395,561 $ 390,094 $ 394,766 $ 382,523 ========== ========== ========== ========== ========== Net Income.............................. $ 155,946 $ 219,044 $ 202,950 $ 194,089 $ 164,891 ========== ========== ========== ========== ========== Earnings on Common Stock................ $ 138,556 $ 193,206 $ 182,107 $ 160,565 $ 140,097 ========== ========== ========== ========== ========== Total Assets............................ $5,935,253 $5,856,106 $5,964,631 $6,208,761 $6,318,183 ========== ========== ========== ========== ========== CAPITALIZATION AT DECEMBER 31: Common Stockholder's Equity............. $1,226,632 $1,082,145 $1,064,839 $ 966,616 $1,008,238 Preferred Stock- Not Subject to Mandatory Redemption.. 96,404 141,475 238,325 238,325 238,325 Subject to Mandatory Redemption...... 105,021 106,288 26,105 116,246 149,710 Long-Term Debt.......................... 1,975,001 2,156,322 2,634,692 2,682,795 2,888,202 ---------- ---------- ---------- ---------- ---------- Total Capitalization.................... $3,403,058 $3,486,230 $3,963,961 $4,003,982 $4,284,475 ========== ========== ========== ========== ========== CAPITALIZATION RATIOS: Common Stockholder's Equity............. 36.0% 31.0% 26.9% 24.1% 23.5% Preferred Stock- Not Subject to Mandatory Redemption.. 2.9 4.1 6.0 6.0 5.6 Subject to Mandatory Redemption...... 3.1 3.0 0.6 2.9 3.5 Long-Term Debt.......................... 58.0 61.9 66.5 67.0 67.4 ----- ----- ----- ----- ----- Total Capitalization.................... 100.0% 100.0% 100.0% 100.0% 100.0% ===== ===== ===== ===== ===== DISTRIBUTION KILOWATT-HOUR DELIVERIES (Millions): Residential............................. 5,370 5,061 5,061 5,278 4,949 Commercial.............................. 4,628 4,907 6,656 6,509 6,353 Industrial.............................. 8,921 9,593 8,320 8,069 8,024 Other................................... 167 166 167 166 165 ------ ------ ------ ------ ------ Total................................... 19,086 19,727 20,204 20,022 19,491 ====== ====== ====== ====== ====== CUSTOMERS SERVED: Residential............................. 677,095 673,852 667,115 667,954 668,470 Commercial.............................. 71,893 70,636 69,103 69,954 68,896 Industrial.............................. 4,725 4,783 4,851 5,090 5,336 Other................................... 289 292 307 223 221 ------- ------- ------- ------- ------- Total................................... 754,002 749,563 741,376 743,221 742,923 ======= ======= ======= ======= ======= Number of Employees..................... 974 1,025 1,046 1,694 1,798
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Corporate Separation - -------------------- Beginning on January 1, 2001, Ohio customers were able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. That legislation required unbundling the price for electricity into its component elements -- including generation, transmission, distribution and transition charges. CEI continues to deliver power to homes and businesses through its existing distribution system and maintain the "provider of last resort" (PLR) obligations under its transition plan. As a result of the transition plan, FirstEnergy's electric utility operating companies (EUOC) entered into power supply agreements whereby FirstEnergy Solutions Corp. (FES) purchases all of the EUOC nuclear generation, and leases EUOC fossil generating facilities. CEI is a "full requirements" customer of FES to enable it to meet its PLR responsibilities in its respective service area. The effect on CEI's reported results of operations during 2001 from FirstEnergy's corporate separation plan and our sale of transmission assets to American Transmission Systems, Inc. (ATSI) in September 2000, are summarized in the following tables:
Corporate Restructuring - 2001 Income Statement Effects ------------------------------------------------------- Increase (Decrease) Corporate Separation ATSI Total ---------- ---- ----- (In millions) Operating Revenues: Power supply agreement with FES........ $334.1 $-- $334.1 Generating units rent.................. 59.1 -- 59.1 Ground lease with ATSI................. -- 2.8 2.8 -------------------------------------------------------------------------------------- Total Operating Revenues Effect........ $393.2 $ 2.8 $396.0 ====================================================================================== Operating Expenses and Taxes: Fossil fuel costs...................... $(97.6)(a) $-- $(97.6) Purchased power costs.................. 597.4 (b) -- 597.4 Other operating costs.................. (90.7)(a) 13.9 (d) (76.8) Provision for depreciation and amortization ........................ -- (5.9)(e) (5.9) General taxes.......................... (3.2)(c) (9.3)(e) (12.5) Income taxes........................... (4.9) 3.4 (1.5) -------------------------------------------------------------------------------------- Total Operating Expenses Effect........ $401.0 $ 2.1 $403.1 ====================================================================================== Other Income............................. $ -- $ 4.8 (f) $ 4.8 ====================================================================================== (a) Transfer of fossil operations to FirstEnergy Generation Company (FGCO). (b) Purchased power from power supply agreement (PSA). (c) Payroll taxes related to employees transferred to FGCO. (d) Transmission services received from ATSI. (e) Depreciation and property taxes related to transmission assets sold to ATSI. (f) Interest on note receivable from ATSI.
Results of Operations - --------------------- Earnings on common stock in 2002 decreased 28.3% to $138.6 million in 2002 from $193.2 million in 2001 and $182.1 million in 2000. The earnings decrease in 2002 primarily resulted from lower operating revenues, which was partially offset by lower operating expenses, net interest charges and preferred stock dividend requirements. Excluding the effects shown in the table above, earnings on common stock increased by 7.4% in 2001 from 2000, being favorably affected by lower operating expenses and net interest charges, which were substantially offset by reduced operating revenues. Operating revenues decreased $240.9 million or 11.6% in 2002 compared with 2001. The lower revenues reflected the effects of a sluggish national economy on our service area, shopping by Ohio customers for alternative energy providers and decreases in wholesale revenues. Retail kilowatt-hour sales declined by 23.9% in 2002 from the prior year, with declines in all customer sectors (residential, commercial and industrial), resulting in a $123.0 million reduction in generation sales revenue. Our lower generation kilowatt-hour sales resulted primarily from customer choice in Ohio. Sales of electric generation by alternative suppliers as a percent of total sales delivered in our franchise area increased to 31.5% in 2002 from 12.9% in 2001, while our share of electric generation sales in our franchise areas decreased by 18.6% compared to the prior year. Distribution deliveries decreased 3.3% in 2002 compared with 2001, which decreased revenues from electricity throughput by $18.9 million in 2002 from the prior year. The lower distribution deliveries resulted from the effect that continued sluggishness in the economy had on demand by commercial and industrial customers which was offset in part by the additional residential demand due to warmer summer weather. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, further reduced operating revenues $43.4 million in 2002 from the prior year. These revenue reductions are deferred for future recovery under our transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers decreased by $43.8 million in 2002 compared to 2001, due to lower kilowatt-hour sales. The reduced kilowatt-hour sales resulted from lower sales to FES reflecting the extended outage at Davis-Besse (see Davis-Besse Restoration). Excluding the effects shown in the table above, operating revenues decreased by $206.8 million or 11.0% in 2001 from 2000. Customer choice in Ohio and the influence of a declining national economy on our regional business activity combined to lower operating revenues. Electric generation services provided by other suppliers in our service area represented 12.9% of total energy delivered in 2001. Retail generation sales declined in all customer categories, resulting in an overall 14.9% reduction in kilowatt-hour sales from the prior year. As part of Ohio's electric utility restructuring law, the implementation of a 5% reduction in generation charges for residential customers reduced operating revenues by approximately $16.6 million in 2001, compared to 2000. Distribution deliveries declined 2.4% in 2001 from the prior year, reflecting the impact of a weaker economy that contributed to lower commercial and industrial kilowatt-hour sales. Operating revenues were also lower in 2001 from the prior year due to the absence of revenues associated with the low-income payment plan now administered by the Ohio Department of Development; there was also a corresponding reduction in other operating costs associated with that change. Revenues from kilowatt-hour sales to wholesale customers declined by $86.7 million in 2001 from 2000, with a corresponding 76.4% reduction in kilowatt-hour sales. Changes in KWH Sales 2002 2001 --------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (23.9)% (14.9)% Wholesale............................. (12.8)% (76.4)% --------------------------------------------------------------------- Total Electric Generation Sales......... (18.9)% (26.4)% ===================================================================== Distribution Deliveries: Residential........................... 6.1% -- % Commercial and industrial............. (6.6)% (3.2)% --------------------------------------------------------------------- Total Distribution Deliveries........... (3.3)% (2.4)% ===================================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $170.4 million in 2002 and increased by $183.7 million in 2001 from 2000. Excluding the effects of restructuring, total 2001 operating expenses and taxes were $219.4 million lower than the prior year. The following table presents changes from the prior year by expense category excluding the impact of restructuring on 2001 changes. Operating Expenses and Taxes - Changes 2002 2001 --------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel and purchased power..................... $(181.2) $(145.6) Nuclear operating costs...................... 98.7 (11.8) Other operating costs........................ 16.2 (7.1) --------------------------------------------------------------------- Total operation and maintenance expenses... (66.3) (164.5) Provision for depreciation and amortization.. (53.3) (20.3) General taxes................................ 2.9 (64.8) Income taxes................................. (53.7) 30.2 -------------------------------------------------------------------- Total operating expenses and taxes......... $(170.4) $(219.4) - ---------------------------------------------------------------------- Lower fuel and purchased power costs in 2002 compared to 2001, resulted from a $177.0 million reduction in power purchased from FES, reflecting lower kilowatt-hours purchased due to reduced kilowatt-hour sales and lower unit prices. Nuclear operating costs increased $98.7 million in 2002, primarily due to approximately $59.1 million of incremental Davis-Besse maintenance costs related to its extended outage (see Davis-Besse Restoration). The $16.2 million increase in other operating costs resulted principally from higher employee benefit costs. The decrease in fuel and purchased power costs in 2001, compared to 2000, reflects the transfer of fossil operations to FGCO, with our power requirements being provided under the PSA. Nuclear operating costs decreased by $11.8 million in 2001 from the prior year due to one less nuclear refueling outage in 2001. Other operating costs decreased $7.1 million in 2001 from the prior year reflecting a reduction in low-income payment plan customer costs and the absence of voluntary early retirement costs in 2001, offset in part by additional planned maintenance work at the Bruce Mansfield Plant and the absence in 2001 of gains from the sale of emission allowances. Charges for depreciation and amortization decreased by $53.3 million in 2002 from 2001 primarily due to higher shopping incentive deferrals and tax-related deferrals under our transition plan and the cessation of goodwill amortization ($38.2 million annually) beginning January 1, 2002, upon implementation of Statement of Financial Accounting Standards No. (SFAS) 142 "Goodwill and Other Intangible Assets." In 2001, depreciation and amortization decreased by $20.3 million from the prior year due to new deferrals for shopping incentives under FirstEnergy's Ohio transition plan. General taxes increased by $2.9 million in 2002 from 2001 principally due to additional property taxes. In 2001, general taxes decreased by $64.8 million from 2000 as a result of reduced property taxes and other state tax changes in connection with the Ohio electric industry restructuring. The reduction in general taxes was partially offset by $20.1 million of new Ohio franchise taxes in 2001, which are classified as state income taxes on the Consolidated Statements of Income. Net Interest Charges Net interest charges continued to trend lower, decreasing by $4.6 million in 2002 and by $9.9 million in 2001, compared to the prior year. We continued to redeem and refinance outstanding debt and preferred stock during 2002 - net redemptions and refinancing activities totaled $291.8 million and $108.7 million, respectively, and will result in annualized savings of $25.5 million. Preferred Stock Dividend Requirements Preferred stock dividend requirements were $8.4 million lower in 2002, compared to the prior year principally due to the completion of $164.7 million in optional and sinking fund preferred stock redemptions. Premiums related to the optional redemptions partially offset the lower dividend requirements. Capital Resources and Liquidity - ------------------------------- Through net debt and preferred stock redemptions, we continued to reduce the cost of debt and preferred stock, and improve our financial position in 2002. During 2002, we reduced our total debt by approximately $206 million. Our common stockholder's equity as a percentage of total capitalization increased to 36% as of December 31, 2002 from 21% at the end of 1997. Over the last five years, we have reduced the average cost of outstanding debt from 8.15% in 1997 to 7.30% in 2002. Changes in Cash Position As of December 31, 2002, we had $30.4 million of cash and cash equivalents, which was principally used to redeem long-term debt in January 2003, compared with $ 0.3 million as of December 31, 2001. The major sources for changes in these balances are summarized below. Cash Flows from Operating Activities Our consolidated net cash from operating activities is provided by our regulated energy services. Net cash provided from operating activities was $317.2 million in 2002 and $365.5 million in 2001. Cash flows provided from 2002 and 2001 operating activities are as follows: Operating Cash Flows 2002 2001 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $319.3 $ 473.4 Working capital and other............ (2.1) (107.9) -------------------------------------------------------------- Total............................ $317.2 $ 365.5 ============================================================== (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Cash Flows from Financing Activities In 2002, the net cash used for financing activities of $140.1 million primarily reflects the redemptions of debt and preferred stock shown below. CEI received an equity contribution of $50 million from FirstEnergy that facilitated CEI's 2002 optional preferred stock redemptions. The following table provides details regarding new issues and redemptions during 2002: Securities Issued or Redeemed in 2002 ------------------------------------- (In millions) New Issues ---------- Pollution Control Notes................... $108.7 Other, principally new financing discounts (1.7) ------------------------------------------------------------ 107.0 Redemptions ----------- First Mortgage Bonds...................... 195.0 Pollution Control Notes................... 78.7 Secured Notes............................. 33.0 Preferred Stock........................... 164.7 Other, principally redemption premiums.... 2.8 - -------------------------------------------------------------- 474.2 Short-term Borrowings, Net..................... $190.9 ============================================================ In 2001, net cash used for financing activities totaled $192.4 million, primarily due to payment of common stock dividends to FirstEnergy. We had about $30.8 million of cash and temporary investments and approximately $288.6 million of short-term indebtedness at the end of 2002. We had the capability to issue $379.3 million of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds. We have no restrictions on the issuance of preferred stock. At the end of 2002, our common equity as a percentage of capitalization, including debt relating to assets held for sale, stood at 36% compared to 31% at the end of 2001. The higher common equity percentage in 2002 compared to 2001 resulted from net redemptions of preferred stock and long-term debt, the additional equity investment from FirstEnergy and the increase in retained earnings. Cash Flows from Investing Activities Net cash used in investing activities totaled $147 million in 2002. The net cash used for investing resulted from property additions, which was offset in part by a reduction of the Shippingport Capital Trust investment. Expenditures for property additions primarily include expenditures supporting our distribution of electricity and capital expenditures related to Davis-Besse (see Davis-Besse Restoration). In 2001, net cash used in investing activities totaled $176 million, principally due to property additions and the sale of property to affiliates as part of corporate separation and the sale to ATSI discussed above. Our cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Over the next three years, we expect to meet our contractual obligations with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets.
Less than 1-3 3-5 More than Contractual Obligations Total 1 Year Years Years 5 Years - --------------------------------------------------------------------------------------------------------------- (In millions) Long-term debt.................. $2,309 $145 $580 $120 $1,464 Short-term borrowings........... 289 289 -- -- -- Preferred stock (1)............. 106 1 2 2 101 Capital leases (2).............. 10 1 2 2 5 Operating leases (2)............ 200 (2) 46 25 131 Purchases (3)................... 413 46 114 100 153 - -------------------------------------------------------------------------------------------------------------- Total...................... $3,327 $480 $744 $249 $1,854 ============================================================================================================== (1) Subject to mandatory redemption. (2) Operating lease payments are net of capital trust receipts of $653.9 million (see Note 2). (3) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.
Our capital spending for the period 2003-2007 is expected to be about $312 million (excluding nuclear fuel) of which approximately $96 million applies to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $53 million, of which about $15 million relates to 2003. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $59 million and $28 million, respectively, as the nuclear fuel is consumed. We sell substantially all of our retail customer receivables, which provided $118 million of off balance sheet financing as of December 31, 2002. On February 22, 2002, Moody's Investors Service changed its credit rating outlook for FirstEnergy from stable to negative. The change was based upon a decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania Public Utility Commission (PPUC) for reconsideration of its decision on the mechanism for sharing merger savings and reversed the PPUC decisions regarding rate relief and accounting deferrals rendered in connection with its approval of the GPU merger. On March 20, 2002, Moody's changed its outlook for CEI from stable to negative and retained a negative outlook for FirstEnergy based on the uncertain outcome of the Davis-Besse extended outage. On April 4, 2002, Standard & Poor's (S&P) changed its outlook for FirstEnergy's credit ratings from stable to negative citing recent developments including: damage to the Davis-Besse reactor vessel head, the Pennsylvania Commonwealth Court decision, and deteriorating market conditions for some sales of FirstEnergy's remaining non-core assets. On July 31, 2002, Fitch revised its rating outlook for FirstEnergy and CEI securities to negative from stable. The revised outlook reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's judgment about NRG's financial ability to consummate the purchase of four power plants (see Note 6 - Sale of Generating Assets) from FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while NRG's liquidity position added uncertainty to FirstEnergy's sale of power plants to NRG, FirstEnergy's ratings would not be affected. S&P found its cash flows sufficiently stable to support a continued (although delayed) program of debt and preferred stock redemption. S&P noted that it would continue to closely monitor our progress on various initiatives. On January 21, 2003, S&P indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa (FirstEnergy's Argentina operations), which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining its current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the Jersey Central Power & Light Company rate case, successful hedging of our short power position, and continued capture of projected merger savings. While we anticipate being prepared to restart the Davis-Besse plant in the spring of 2003, the Nuclear Regulatory Commission (NRC) must authorize the unit's restart following a formal inspection process prior to our returning the unit to service. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which we reduce debt could put additional pressure on our credit ratings. Other Obligations Obligations not included on our Consolidated Balance Sheet primarily consist of a sale and leaseback arrangement involving the Bruce Mansfield Plant, which is reflected in the operating lease payments disclosed above (see Note 2 - Leases). The present value as of December 31, 2002, of this sale and leaseback operating lease commitments, net of trust investments, total $156 million. Interest Rate Risk - ------------------ Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the following table. We are subject to the inherent risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 2, our investment in the Shippingport Capital Trust effectively reduces future lease obligations, also reducing interest rate risk. Changes in the market value of our nuclear decommissioning trust funds had been recognized by making corresponding changes to the decommissioning liability, as described in Note 1 - Utility Plant and Depreciation. In conjunction with the adoption of SFAS 143, "Accounting for Asset Retirement Obligations," on January 1, 2003, we reclassified unrealized gains and losses to other comprehensive income in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity." While fluctuations in the fair value of our Ohio EUOCs' trust balances will eventually affect earnings (affecting OCI initially) based on the guidance provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from ratepayers the difference between the investments held in trust and their retirement obligations. Thus, in absence of disallowed costs, there will be no earning effect from fluctuations in their decommissioning trust balances today or in the future. As of December 31, 2002, decommissioning trust balances totaled $1.050 billion with $698 million held by our Ohio EUOC and the balance held by our non-Ohio EUOC. As of year end 2002, trust balances included 51% of equity and 49% of debt instruments. The table below presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.
Comparison of Carrying Value to Fair Value - ------------------------------------------------------------------------------------------------------------------- There- Fair 2003 2004 2005 2006 2007 after Total Value - ------------------------------------------------------------------------------------------------------------------- (Dollars in millions) Assets - ------------------------------------------------------------------------------------------------------------------- Investments other than Cash and Cash Equivalents: Fixed Income................. $ 48 $ 1 $ 32 $ 31 $ 25 $ 494 $ 631 $ 701 Average interest rate..... 7.8% 7.8% 8.0% 7.9% 7.7% 7.1% 7.2% - ------------------------------------------------------------------------------------------------------------------- Liabilities - ------------------------------------------------------------------------------------------------------------------- Long-term Debt: Fixed rate................... $145 $280 $300 $ -- $120 $1,246 $2,091 $2,275 Average interest rate .... 7.3% 7.7% 9.5% 7.1% 7.2% 7.6% Variable rate................ $ 218 $ 218 $ 218 Average interest rate..... 1.8% 1.8% Short-term Borrowings........ $289 $ 289 $ 289 Average interest rate..... 1.8% 1.8% - ------------------------------------------------------------------------------------------------------------------- Preferred Stock.............. $ 1 $ 1 $ 1 $ 1 $ 1 $ 101 $ 106 $ 113 Average dividend rate .... 7.4% 7.4% 7.4% 7.4% 7.4% 9.0% 8.9% - -------------------------------------------------------------------------------------------------------------------
Equity Price Risk - ----------------- Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $209 million and $208 million as of December 31, 2002 and 2001, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $21 million reduction in fair value as of December 31, 2002 (see Note 1 - Supplemental Cash Flows Information). Outlook - ------- Our industry continues to transition to a more competitive environment. In 2001, all our customers could select alternative energy suppliers. We continue to deliver power to homes and businesses through our existing distribution systems, which remain regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, we have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters Beginning on January 1, 2001, Ohio customers were able to choose their electricity suppliers. Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of our Ohio customers elects to obtain power from an alternative supplier, we reduce the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive for our customers), and the customer receives a generation charge from the alternative supplier. We have continuing PLR responsibility to our franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by the Public Utilities Commission of Ohio (PUCO), PPUC and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of our regulatory assets are expected to continue to be recovered under the provisions of our transition plan as discussed below. Our regulatory assets as of December 2002 and 2001 are $939.8 million and $874.5 million, respectively. The transition cost portion of rates provides for recovery of certain amounts not otherwise recoverable in a competitive generation market (such as regulatory assets). Transition costs are paid by all customers whether or not they choose an alternative supplier. Under the PUCO-approved transition plan, we assumed the risk of not recovering up to $170 million of transition revenue if the rate of customers (excluding contracts and full-service accounts) switching from our service to an alternative supplier did not reach 20% for any consecutive twelve-month period by December 31, 2005 - the end of the market development period. That goal was achieved in 2002. Accordingly, CEI does not believe that there will be any regulatory action reducing the recoverable transition costs. As part of our Ohio transition plan we are obligated to supply electricity to customers who do not choose an alternative supplier. We are also required to provided 400 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within our service area. Our competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in our franchise area. In 2003, the total peak load forecasted for customers electing to stay with us, including the 400 MW of low cost supply and the load served by our affiliate is 4175 MW. Davis-Besse Restoration On April 30, 2002, the NRC initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FirstEnergy Nuclear Operating Company (FENOC), an affiliated company, in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, we have made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FENOC is also accelerating maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, FENOC discussed plans to test the bottom of the reactor for leaks and to install a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FENOC anticipates that the unit will be ready for restart in the spring of 2003 after completion of the additional maintenance work and regulatory reviews. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed our plans to reduce post-merger debt levels we believe such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of our investment in the plant (see Significant Accounting Policies below). The actual costs (capital and expense) associated with the extended Davis-Besse outage (CEI's share - 51.38%) in 2002 and estimated costs in 2003 are: Costs of Davis-Besse Extended Outage 100% -------------------------------------------------------------------- (In millions) 2002 - Actual ------------- Capital Expenditures: Reactor head and restart.......................... $ 63.3 Incremental Expenses (pre-tax): Maintenance....................................... 115.0 Fuel and purchased power.......................... 119.5 Total............................................. $234.5 2003 - Estimated ---------------- Primarily operating expenses (pre-tax): Maintenance (including acceleration of programs).. $50 Replacement power per month....................... $12-18 -------------------------------------------------------------------- Environmental Matters We believe we are in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 5 - Environmental Matters). We continue to evaluate our compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. We have been named as "potentially responsible parties" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, 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, our proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. We have total accrued liabilities aggregating approximately $2.9 million as of December 31, 2002. The effects of our compliance with regard to environmental matters could have a material adverse effect on our earnings and competitive position. These environmental regulations affect our earnings and competitive position to the extent we compete with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. We believe we are in material compliance with existing regulations, but are unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Significant Accounting Policies - ------------------------------- We prepare our consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect our financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. Our more significant accounting policies are described below. Regulatory Accounting CEI is subject to regulation that sets the prices (rates) we are permitted to charge our customers based on our costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio and Pennsylvania, a significant amount of regulatory assets have been recorded. As of December 31, 2002, CEI's regulatory assets totaled $939.8 million. We continually review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for KWH that have been delivered but not yet been billed through the end of the year. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of KWH usage by residential, commercial and industrial customers o KWH usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as our merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, we reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000. Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. The market values of our pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002, 2001 and 2000, plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, we will not be required to fund of our pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to our 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. The effect on our SFAS 87 and 106 costs and liabilities from changes in key assumptions are as follows:
Increase in Costs from Adverse Changes in Key Assumptions ----------------------------------------------------------------------------------------------- Assumption Adverse Change Pension OPEB Total ----------------------------------------------------------------------------------------------- (In millions) Increase in Costs ----------------- Discount rate................ Decrease by 0.25% $0.4 $0.4 $0.8 Long-term return on assets... Decrease by 0.25% 0.3 -- 0.3 Health care trend rate....... Increase by 1% na 1.0 1.0 Increase in Minimum Pension Liability ------------------------------------- Discount rate................ Decrease by 0.25% 9.1 na 9.1 ------------------------------------------------------------------------------------------------
As a result of the reduced market value of our pension plan assets, we were required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. We eliminated our prepaid pension asset of $39.3 million and established a minimum liability of $52.1 million, recording an intangible asset of $15.9 million and reducing OCI by $44.1 million (recording a related deferred tax benefit of $31.4 million). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002 increased due to the lower discount rate assumed and reduced market value of plan assets as of December 31, 2002. Our non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $6 million and $2 million, respectively - - a total of $8 million in 2003 as compared to 2002. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset, is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur we would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill. The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. As of December 31, 2002, we had approximately $1.4 billion of goodwill. Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- SFAS 143, "Accounting for Asset Retirement Obligations" In June 2001, the FASB issued SFAS 143. The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize regulatory assets or liabilities if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. We have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $173 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $19 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144. No impairment was indicated. The asset retirement liability at the date of adoption was $238 million. As of December 31, 2002, CEI had recorded decommissioning liabilities of $240 million, including unrealized losses on decommissioning trust funds of $0.4 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. The cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $155 million increase to income ($91 million net of tax). The $0.4 million of unrealized losses ($0.2 million net of tax) included in the decommissioning liability balances as of December 31, 2002, were offset against OCI upon adoption of SFAS 143. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities" This statement, which was issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time they are incurred rather than when management commits to a plan of exit or disposal. It also requires the use of fair value for the measurement of such liabilities. The new standard supersedes guidance provided by EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This new standard was effective for exit and disposal activities initiated after December 31, 2002. Since it is applied prospectively, there will be no impact upon adoption. However, SFAS 146 could change the timing and amount of costs recognized in connection with future exit or disposal activities. FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002 (see Guarantees and Other Assurances). It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions beginning in the first interim or annual reporting period after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. We currently have transactions with entities which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. We currently consolidate the majority of these entities and believe we will continue to consolidate following the adoption of FIN 46. One of these entities we are currently consolidating is the Shippingport Capital Trust which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of our interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated parties and 0.34 percent equity interest by Toledo Edison Capital Corp., an affiliated company.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2002 2001 2000 - -------------------------------------------------------------------------------------------------------------- (In thousands) OPERATING REVENUES (Note 1)................................. $1,835,371 $2,076,222 $1,887,039 ---------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel and purchased power (Note 1)........................ 587,108 768,306 414,127 Nuclear operating costs (Note 1)......................... 238,513 139,787 151,571 Other operating costs (Note 1)........................... 307,142 290,945 374,818 ---------- ---------- ---------- Total operation and maintenance expenses............... 1,132,763 1,199,038 940,516 Provision for depreciation and amortization.............. 141,427 194,717 220,915 General taxes............................................ 147,804 144,948 222,297 Income taxes............................................. 88,231 141,958 113,217 ---------- ---------- ---------- Total operating expenses and taxes..................... 1,510,225 1,680,661 1,496,945 ---------- ---------- ---------- OPERATING INCOME............................................ 325,146 395,561 390,094 OTHER INCOME (Note 1)....................................... 15,971 13,292 12,568 ---------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES.......................... 341,117 408,853 402,662 ---------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt............................... 179,140 191,695 199,444 Allowance for borrowed funds used during construction........................................... (4,331) (2,293) (2,027) Other interest expense................................... 1,462 32 2,295 Subsidiary's preferred stock dividend requirements....... 8,900 375 -- ---------- ---------- ---------- Net interest charges..................................... 185,171 189,809 199,712 ---------- ---------- ---------- NET INCOME.................................................. 155,946 219,044 202,950 PREFERRED STOCK DIVIDEND REQUIREMENTS............................................. 17,390 25,838 20,843 ---------- ---------- ---------- EARNINGS ON COMMON STOCK.................................... $ 138,556 $ 193,206 $ 182,107 ========== ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------ (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $4,045,465 $4,071,134 Less-Accumulated provision for depreciation.................................... 1,824,884 1,725,727 ---------- ---------- 2,220,581 2,345,407 ---------- ---------- Construction work in progress- Electric plant............................................................... 153,104 66,266 Nuclear fuel................................................................. 45,354 21,712 ---------- ---------- 198,458 87,978 ---------- ---------- 2,419,039 2,433,385 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust (Note 2)............................................ 435,907 475,543 Nuclear plant decommissioning trusts........................................... 230,527 211,605 Long-term notes receivable from associated companies........................... 102,978 103,425 Other.......................................................................... 21,004 24,611 ---------- ---------- 790,416 815,184 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 30,382 296 Receivables- Customers.................................................................... 11,317 17,706 Associated companies......................................................... 74,002 75,113 Other (less accumulated provisions of $1,015,000 for uncollectible accounts at both dates)............................................................. 134,375 99,716 Notes receivable from associated companies..................................... 447 415 Materials and supplies, at average cost- Owned........................................................................ 18,293 20,230 Under consignment............................................................ 38,094 28,533 Prepayments and other.......................................................... 4,217 31,634 ---------- ---------- 311,127 273,643 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 939,804 874,488 Goodwill....................................................................... 1,370,639 1,370,639 Property taxes................................................................. 79,430 80,470 Other.......................................................................... 24,798 8,297 ---------- ---------- 2,414,671 2,333,894 ---------- ---------- $5,935,253 $5,856,106 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity.................................................... $1,226,632 $1,082,145 Preferred stock- Not subject to mandatory redemption.......................................... 96,404 141,475 Subject to mandatory redemption.............................................. 5,021 6,288 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures (Note 3)..... 100,000 100,000 Long-term debt................................................................. 1,975,001 2,156,322 ---------- ---------- 3,403,058 3,486,230 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock........................... 388,190 526,630 Accounts payable- Associated companies......................................................... 267,664 81,463 Other........................................................................ 14,583 30,332 Notes payable to associated companies.......................................... 288,583 97,704 Accrued taxes................................................................. 126,262 129,830 Accrued interest............................................................... 51,767 57,101 Other.......................................................................... 64,324 60,664 ---------- ---------- 1,201,373 983,724 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes.............................................. 659,044 637,339 Accumulated deferred investment tax credits.................................... 72,125 76,187 Nuclear plant decommissioning costs............................................ 239,720 220,798 Pensions and other postretirement benefits..................................... 171,968 231,365 Other.......................................................................... 187,965 220,463 ---------- ---------- 1,330,822 1,386,152 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 2 and 5)................................................................ ---------- ---------- $5,935,253 $5,856,106 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION As of December 31, 2002 2001 - ----------------------------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, without par value, authorized 105,000,000 shares 79,590,689 shares outstanding.................................................... $ 981,962 $ 931,962 Accumulated other comprehensive loss (Note 3G)..................................... (44,051) -- Retained earnings (Note 3A)........................................................ 288,721 150,183 ---------- ---------- Total common stockholder's equity................................................ 1,226,632 1,082,145 ---------- ---------- Number of Shares Optional Outstanding Redemption Price ---------------- -------------------- 2002 2001 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK (Note 3C): Cumulative, without par value- Authorized 4,000,000 shares Not Subject to Mandatory Redemption: $ 7.40 Series A....................... 500,000 500,000 $101.00 $50,500 50,000 50,000 $ 7.56 Series B....................... -- 450,000 -- -- -- 45,071 Adjustable Series L.................... 474,000 474,000 100.00 47,400 46,404 46,404 $42.40 Series T........................ -- 200,000 -- -- -- 96,850 --------- --------- ------- ---------- ---------- 974,000 1,624,000 97,900 96,404 238,325 Redemption Within One Year............... -- (96,850) --------- --------- ------- ---------- ---------- Total Not Subject to Mandatory Redemption............................. 974,000 1,624,000 $97,900 96,404 141,475 ========= ========= ======= ---------- ---------- Subject to Mandatory Redemption (Note 3D): $ 7.35 Series C....................... 60,000 70,000 101.00 $ 6,060 6,021 7,030 $90.00 Series S........................ -- 17,750 -- -- -- 17,268 --------- --------- ------- ---------- ---------- 60,000 87,750 6,060 6,021 24,298 Redemption Within One Year............... (1,000) (18,010) --------- --------- ------- ---------- ---------- Total Subject to Mandatory Redemption 60,000 87,750 $ 6,060 5,021 6,288 ========= ========= ======= ---------- ---------- COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES (Note 3E): Cumulative, $25 stated value- Authorized 4,000,000 shares Subject to Mandatory Redemption: 9.00%.................................. 4,000,000 4,000,000 -- $ -- 100,000 100,000 ========= ========= ======= ---------- ---------- LONG-TERM DEBT (Note 3F): First mortgage bonds: 7.625% due 2002.......................................................................... -- 195,000 7.375% due 2003.......................................................................... 100,000 100,000 9.500% due 2005.......................................................................... 300,000 300,000 6.860% due 2008.......................................................................... 125,000 125,000 9.000% due 2023.......................................................................... 150,000 150,000 ---------- ---------- Total first mortgage bonds............................................................. 675,000 870,000 ---------- ---------- Unsecured notes: 6.000% due 2013.......................................................................... 78,700 -- * 5.580% due 2033.......................................................................... 27,700 27,700 ---------- ---------- Total unsecured notes.................................................................. 106,400 27,700 ---------- ----------
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd) As of December 31, 2002 2001 - --------------------------------------------------------------------------------------------------------------------- (In thousands) LONG-TERM DEBT (Cont'd): Secured notes: 7.000% due 2003-2009............................................................. 1,760 1,790 7.850% due 2002.................................................................. -- 5,000 8.130% due 2002.................................................................. -- 28,000 7.750% due 2003.................................................................. 15,000 15,000 7.670% due 2004.................................................................. 280,000 280,000 7.130% due 2007.................................................................. 120,000 120,000 7.430% due 2009.................................................................. 150,000 150,000 8.000% due 2013.................................................................. -- 78,700 *1.176% due 2015.................................................................. 39,835 39,835 7.880% due 2017.................................................................. 300,000 300,000 *1.180% due 2018.................................................................. 72,795 72,795 *1.550% due 2020.................................................................. 47,500 47,500 6.000% due 2020.................................................................. 62,560 62,560 6.100% due 2020.................................................................. 70,500 70,500 9.520% due 2021.................................................................. 7,500 7,500 6.850% due 2023.................................................................. 30,000 30,000 8.000% due 2023.................................................................. 46,100 46,100 7.625% due 2025.................................................................. 53,900 53,900 7.700% due 2025.................................................................. 43,800 43,800 7.750% due 2025.................................................................. 45,150 45,150 5.375% due 2028.................................................................. 5,993 5,993 5.350% due 2030.................................................................. 23,255 23,255 4.600% due 2030.................................................................. 81,640 81,640 *1.300% due 2033.................................................................. 30,000 -- ---------- ---------- Total secured notes............................................................ 1,527,288 1,609,018 ---------- ---------- Capital lease obligations (Note 2)................................................. 6,351 6,740 ---------- ---------- Net unamortized premium on debt.................................................... 47,152 54,634 ---------- ---------- Long-term debt due within one year................................................. (387,190) (411,770) ---------- ---------- Total long-term debt........................................................... 1,975,001 2,156,322 ---------- ---------- TOTAL CAPITALIZATION.................................................................. $3,403,058 $3,486,230 ========== ========== * Denotes variable rate issue with December 31, 2002 interest rate shown. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Accumulated Other Comprehensive Number Carrying Comprehensive Retained Income of Shares Value Income (Loss) Earnings ------------- --------- ----- ------------- -------- (Dollars in thousands) Balance, January 1, 2000....................... 79,590,689 $931,962 $ -- $ 34,654 Net income.................................. $202,950 202,950 ======== Cash dividends on preferred stock........... (20,727) Cash dividends on common stock.............. (84,000) - ----------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000..................... 79,590,689 931,962 -- 132,877 Net income.................................. $219,044 219,044 ======== Cash dividends on preferred stock........... (25,838) Cash dividends on common stock.............. (175,900) - ----------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001..................... 79,590,689 931,962 -- 150,183 Net income.................................. $155,946 155,946 Minimum liability for unfunded retirement benefits, net of $(31,359,000) of income taxes.............................. (44,051) (44,051) -------- Comprehensive income........................ $111,895 ======== Equity contribution from parent............. 50,000 Cash dividends on preferred stock........... (12,665) Preferred stock redemption premiums......... (4,743) - ----------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002..................... 79,590,689 $981,962 $(44,051) $ 288,721 =================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemption -------------------- -------------------- Number Carrying Number Carrying of Shares Value of Shares Value --------- ----- --------- ----- (Dollars in thousands) Balance, January 1, 2000.......... 1,624,000 $238,325 219,680 $149,710 Redemptions- $ 7.35 Series C .............. (10,000) (1,000) $88.00 Series E............... (3,000) (3,000) $91.50 Series Q............... (10,714) (10,714) $90.00 Series S............... (18,750) (18,750) Amortization of fair market value adjustments- $ 7.35 Series C .............. (69) $88.00 Series R............... (3,872) $90.00 Series S............... (5,734) ---------------------------------------------------------------------------------------- Balance, December 31, 2000........ 1,624,000 238,325 177,216 106,571 Issues 9.00%......................... 4,000,000 100,000 Redemptions- $ 7.35 Series C (10,000) (1,000) $88.00 Series R............... (50,000) (50,000) $91.50 Series Q............... (10,716) (10,716) $90.00 Series S............... (18,750) (18,750) Amortization of fair market value adjustments- $ 7.35 Series C (11) $88.00 Series R............... (1,128) $90.00 Series S............... (668) ---------------------------------------------------------------------------------------- Balance, December 31, 2001........ 1,624,000 238,325 4,087,750 124,298 Redemptions $ 7.56 Series B............... (450,000) (45,071) $42.40 Series T............... (200,000) (96,850) $ 7.35 Series C............... (10,000) (1,000) $90.00 Series S............... (17,750) (17,010) Amortization of fair market value adjustments- $7.35 Series C............... (9) $90.00 Series S............... (258) ---------------------------------------------------------------------------------------- Balance, December 31, 2002........ 974,000 $96,404 4,060,000 $106,021 ======================================================================================== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------ (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income........................................................... $155,946 $ 219,044 $ 202,950 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization..................... 141,427 194,717 220,915 Nuclear fuel and lease amortization............................. 21,044 30,539 37,217 Other amortization.............................................. (15,008) (14,071) (11,635) Deferred income taxes, net...................................... 19,973 46,976 22,373 Investment tax credits, net..................................... (4,062) (3,770) (3,617) Receivables..................................................... (27,159) 30,942 (16,875) Materials and supplies.......................................... (7,624) 15,949 (1,697) Accounts payable................................................ 47,147 (45,542) 20,817 Other (Note 7).................................................. (14,529) (109,289) (44,188) -------- --------- --------- Net cash provided from operating activities................... 317,155 365,495 426,260 -------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt.................................................. 106,981 -- -- Preferred stock................................................. -- 96,739 -- Short-term borrowings, net...................................... 190,879 69,118 -- Equity contributions from parent................................ 50,000 -- -- Redemptions and Repayments- Preferred stock................................................. (164,674) (80,466) (33,464) Long-term debt.................................................. (309,480) (74,230) (212,771) Short-term borrowings, net...................................... -- -- (74,885) Dividend Payments- Common stock.................................................... -- (175,900) (84,000) Preferred stock................................................. (13,782) (27,645) (30,518) -------- --------- --------- Net cash provided from (used for) financing activities........ (140,076) (192,384) (435,638) -------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions................................................... (163,199) (154,927) (96,236) Loans to associated companies........................................ -- (11,117) (93,106) Loan payments from associated companies.............................. 415 383 -- Capital trust investments............................................ 39,636 16,287 25,426 Sale of assets to associated companies............................... -- 11,117 197,902 Other (Note 7)....................................................... (23,845) (37,413) (22,129) -------- --------- --------- Net cash provided from (used for) investing activities........ (146,993) (175,670) 11,857 -------- --------- --------- Net increase (decrease) in cash and cash equivalents................. 30,086 (2,559) 2,479 Cash and cash equivalents at beginning of year....................... 296 2,855 376 -------- --------- --------- Cash and cash equivalents at end of year............................. $ 30,382 $ 296 $ 2,855 ======== ========= ========= SUPPLEMENTAL CASH FLOWS INFORMATION: Cash Paid During the Year- Interest (net of amounts capitalized)........................... $186,040 $ 196,001 $ 208,085 ======== ========= ========= Income taxes.................................................... $121,668 $ 131,801 $ 109,212 ======== ========= ========= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF TAXES For the Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: Real and personal property......................................... $ 77,516 $ 72,665 $131,331 State gross receipts*.............................................. -- 27,169 79,709 Ohio kilowatt-hour excise*......................................... 66,775 42,608 -- Social security and unemployment................................... 3,478 2,752 11,464 Other.............................................................. 35 (246) (207) -------- --------- -------- Total general taxes......................................... $147,804 $ 144,948 $222,297 ======== ========= ======== PROVISION FOR INCOME TAXES: Currently payable- Federal......................................................... $ 72,467 $ 97,675 $106,986 State........................................................... 13,466 17,767 959 -------- --------- -------- 85,933 115,442 107,945 -------- --------- -------- Deferred, net- Federal......................................................... 12,592 42,566 23,265 State........................................................... 7,381 4,410 (892) -------- --------- -------- 19,973 46,976 22,373 -------- --------- -------- Investment tax credit amortization................................. (4,062) (3,770) (3,617) -------- --------- -------- Total provision for income taxes............................ $101,844 $ 158,648 $126,701 ======== ========= ======== INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating income................................................... $ 88,231 $ 141,958 $113,217 Other income....................................................... 13,613 16,690 13,484 -------- --------- -------- Total provision for income taxes............................ $101,844 $ 158,648 $126,701 ======== ========= ======== RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes...................... $257,790 $ 377,692 $329,651 ======== ========= ======== Federal income tax expense at statutory rate....................... $ 90,227 $ 132,192 $115,378 Increases (reductions) in taxes resulting from- State income taxes, net of federal income tax benefit........... 13,551 14,415 44 Amortization of investment tax credits.......................... (4,062) (3,770) (3,617) Amortization of tax regulatory assets........................... 753 766 693 Amortization of goodwill........................................ -- 13,380 13,359 Other, net...................................................... 1,375 1,665 844 -------- --------- -------- Total provision for income taxes............................ $101,844 $ 158,648 $126,701 ======== ========= ======== ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences......................................... $473,506 $ 463,344 $495,588 Competitive transition charge...................................... 269,365 279,198 133,248 Unamortized investment tax credits................................. (27,839) (29,528) (35,341) Unused alternative minimum tax credits............................. -- -- (27,115) Deferred gain for asset sale to affiliated company................. 43,193 49,735 46,583 Other comprehensive income......................................... (31,359) -- -- Other (Note 7)..................................................... (67,822) (125,410) (21,215) -------- --------- -------- Net deferred income tax liability........................... $659,044 $ 637,339 $591,748 ======== ========= ======== * Collected from customers through regulated rates and included in revenue in the Consolidated Statements of Income. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include The Cleveland Electric Illuminating Company (Company) and its wholly owned subsidiaries, Centerior Funding Corporation (CFC) and Centerior Financing Trust (CFT). All significant intercompany transactions have been eliminated. The Company is a wholly owned subsidiary of FirstEnergy Corp. FirstEnergy holds directly all of the issued and outstanding common shares of its principal electric utility operating subsidiaries, including the Company, Ohio Edison Company (OE), The Toledo Edison Company (TE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). JCP&L, Met-Ed and Penelec were formerly wholly owned subsidiaries of GPU, Inc. which merged with FirstEnergy on November 7, 2001. The Company follows the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. (A) CONSOLIDATION- The Company consolidates all majority-owned subsidiaries, after eliminating the effects of intercompany transactions. Non-majority owned investments, including investments in limited liability companies, partnerships and joint ventures, are accounted for under the equity method when the Company is able to influence their financial or operating policies. Investments in corporations resulting in voting control of 20% or more are presumed to be equity method investments. Limited partnerships are evaluated in accordance with SEC Staff D-46, "Accounting for Limited Partnership Investments" and American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence. For all remaining investments (excluding those within the scope of SFAS 115) the Company applies the cost method. (B) REVENUES- The Company's principal business is providing electric service to customers in northeastern Ohio. The Company's retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service through the end of the year. Receivables from customers include sales to residential, commercial and industrial customers located in the Company's service area and sales to wholesale customers. There was no material concentration of receivables at December 31, 2002 or 2001, with respect to any particular segment of the Company's customers. The Company and TE sell substantially all of their retail customers' receivables to CFC. CFC subsequently transfers the receivables to a trust (a SFAS 140 "qualified special purpose entity") under an asset-backed securitization agreement. Transfers are made in return for an interest in the trust (41% as of December 31, 2002), which is stated at fair value, reflecting adjustments for anticipated credit losses. The average collection period for billed receivables is 28 days. Given the short collection period after billing, the fair value of CFC's interest in the trust approximates the stated value of its retained interest in underlying receivables after adjusting for anticipated credit losses. Accordingly, subsequent measurements of the retained interest under SFAS 115 (as an available-for-sale financial instrument) result in no material change in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated credit losses would not have significantly affected the Company's retained interest in the pool of receivables through the trust. Of the $272 million sold to the trust and outstanding as of December 31, 2002, the Company had a retained interest in $111 million of the receivables included as other receivables on the Consolidated Balance Sheets. Accordingly, receivables recorded on the Consolidated Balance Sheets were reduced by approximately $161 million due to these sales. Collections of receivables previously transferred to the trust and used for the purchase of new receivables from CFC during 2002, totaled approximately $2.2 billion. The Company processed receivables for the trust and received servicing fees of approximately $2.5 million in 2002. Expenses associated with the factoring discount related to the sale of receivables were $4.7 million in 2002. (C) REGULATORY PLAN- 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 the Company, OE and TE as modified by a settlement agreement with major parties to the transition plan. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation" to the Company's nonnuclear generation business was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $1.6 billion net of deferred income taxes and transition costs related to regulatory assets as filed of $1.4 billion net of deferred income taxes, with recovery through no later than 2008 for the Company, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $0.2 billion, net of deferred income taxes of impaired generating assets recognized as regulatory assets as described further below, $0.4 billion, net of deferred income taxes of above market operating lease costs and $0.5 billion, net of deferred income taxes of additional plant costs that were reflected on the Company's regulatory financial statements. Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 400 megawatts (MW) of generation capacity through 2005 at established prices for sales to the Company's retail customers. Customer prices are frozen through the five-year market development period except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Company was authorized increases in annual revenues aggregating approximately $4 million to recover its higher tax costs resulting from the Ohio deregulation legislation. The Company's customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be accomplished by extending the 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 period could have been shortened for the Company to reduce recovery by as much as $170 million. The Company achieved its required 20% customer shopping goals in 2002. Accordingly, the Company believes that there will be no regulatory action reducing the recoverable transition costs. The application of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", (SFAS 71), has been discontinued with respect to the Company's generation operations. The SEC issued interpretive guidance regarding asset impairment measurement concluding that any supplemental regulated cash flows such as a competitive transition charge should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance $304 million of impaired plant investments were recognized by the Company as regulatory assets recoverable as transition costs through future regulatory cash flows. Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued were $1.406 billion as of December 31, 2002. (D) UTILITY PLANT AND DEPRECIATION- Utility plant reflects the original cost of construction (except for the Company's nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 3.4% in 2002, 3.2% in 2001 and 3.4% in 2000. Annual depreciation expense includes approximately $29.0 million for future decommissioning costs applicable to the Company's ownership interests in three nuclear generating units (Beaver Valley Unit 2, Davis-Besse Unit 1 and Perry Unit 1). The Company's share of the future obligation to decommission these units is approximately $682 million in current dollars and (using a 4.0% escalation rate) approximately $1.6 billion in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Payments for decommissioning are expected to begin in 2016, when actual decommissioning work begins. The Company has recovered approximately $192 million for decommissioning through its electric rates from customers through December 31, 2002. The Company has also recognized an estimated liability of approximately $6.2 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy, as required by the Energy Policy Act of 1992. In June 2001, the Financial Accounting Standards Board issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. The Company has identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143, asset retirement costs of $173 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $19 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets". No impairment was indicated. The asset retirement liability at the date of adoption will be $238 million. As of December 31, 2002, the Company had recorded decommissioning liabilities of $240 million, including unrealized losses on decommissioning trust funds of $0.4 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. The cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $155 million increase to income, or $91 million net of tax. The $0.4 million of unrealized losses, $0.2 million net of tax, included in the decommissioning liability balances as of December 31, 2002, was offset against other comprehensive income (OCI) upon adoption of SFAS 143. The FASB approved SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. Under SFAS 142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill is tested for impairment at least on an annual basis - - based on the results of the transition analysis and the 2002 annual analysis, no impairment of the Company's goodwill is required. Prior to the adoption of SFAS 142, the Company amortized about $38.2 million of goodwill annually. The goodwill balance as of December 31, 2002 and 2001 was $1.371 billion. The following table shows what net income would have been if goodwill amortization had been excluded from prior periods: 2002 2001 2000 ---- ---- ---- (In thousands) Reported net income.................. $155,946 $219,044 $202,950 Add back goodwill amortization....... -- 38,230 38,170 -------- -------- -------- Adjusted net income.................. $155,946 $257,274 $241,120 ======== ======== ======== (E) COMMON OWNERSHIP OF GENERATING FACILITIES- The Company, together with TE and OE and its wholly owned subsidiary, Pennsylvania Power Company (Penn), own and/or lease, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly owned facility in the same proportion as its interest. The Company's portion of operating expenses associated with jointly owned facilities is included in the corresponding operating expenses on the Consolidated Statements of Income. The amounts reflected on the Consolidated Balance Sheet under utility plant at December 31, 2002 include the following:
Utility Accumulated Construction Ownership/ Plant Provision for Work in Leasehold Generating Units in Service Depreciation Progress Interest - ---------------------------------------------------------------------------------------------------- (In millions) W. H. Sammis Unit 7........... $ 179.8 $125.4 $ -- 31.20% Bruce Mansfield Units 1, 2 and 3 ...................... 85.2 38.6 40.6 20.42% Beaver Valley Unit 2.......... 3.9 0.4 10.7 24.47% Davis-Besse................... 219.4 46.6 60.1 51.38% Perry......................... 633.0 147.1 4.9 44.85% ------------------------------------------------------------------------------------------------- Total...................... $1,121.3 $358.1 $116.3 . ====================================================================================================
The Bruce Mansfield Plant is being leased through a sale and leaseback transaction (see Note 2) and the above-related amounts represent construction expenditures subsequent to the transaction. (F) NUCLEAR FUEL- Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Company amortizes the cost of nuclear fuel based on the rate of consumption. (G) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 3B). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows: 2002 2001 2000 - -------------------------------------------------------------------------- Valuation assumptions: Expected option term (years). 8.1 8.3 7.6 Expected volatility.......... 23.31% 23.45% 21.77% Expected dividend yield...... 4.36% 5.00% 6.68% Risk-free interest rate...... 4.60% 4.67% 5.28% Fair value per option.......... $6.45 $4.97 $2.86 ------------------------------------------------------------------------- The effects of applying fair value accounting to FirstEnergy's stock options would not materially effect the Company's net income. (H) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. The Company is included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Company recognizing any tax losses or credits it contributed to the consolidated return. (I) RETIREMENT BENEFITS- FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all of the Company's full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. On December 31, 2001, the GPU pension plans were merged with the FirstEnergy plan. The Company uses the projected unit credit method for funding purposes and was not required to make pension contributions during the three years ended December 31, 2002. The assets of the FirstEnergy pension plan consist primarily of common stocks, United States government bonds and corporate bonds. The Company provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company pays insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Company. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. As a result of the reduced market value of FirstEnergy's pension plan assets, it was required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002.FirstEnergy's accumulated benefit obligation of $3.438 billion exceeded the fair value of plan assets ($2.889 billion) resulting in a minimum pension liability of $548.6 million. FirstEnergy eliminated its prepaid pension asset of $286.9 million ($39.3 million) and established a minimum liability of $548.6 million (Company - $52.1 million), recording an intangible asset of $78.5 million (Company - $15.9 million) and reducing OCI by $444.2 million (Company - $44.1 million) (recording a related deferred tax asset of $312.8 million (Company - $31.4 million)). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002, increased due to the lower discount rate and asset returns assumed as of December 31, 2002. The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Other Pension Benefits Postretirement Benefits ---------------- ----------------------- 2002 2001 2002 2001 - ---------------------------------------------------------------------------------------------- (In millions) Change in benefit obligation: Benefit obligation as of January 1....... $3,547.9 $1,506.1 $1,581.6 $ 752.0 Service cost............................. 58.8 34.9 28.5 18.3 Interest cost............................ 249.3 133.3 113.6 64.4 Plan amendments.......................... -- 3.6 (121.1) -- Actuarial loss........................... 268.0 123.1 440.4 73.3 Voluntary early retirement program....... -- -- -- 2.3 GPU acquisition.......................... (11.8) 1,878.3 110.0 716.9 Benefits paid............................ (245.8) (131.4) (83.0) (45.6) ------------------------------------------------------------------------------------------- Benefit obligation as of December 31..... 3,866.4 3,547.9 2,070.0 1,581.6 ------------------------------------------------------------------------------------------- Change in fair value of plan assets: Fair value of plan assets as of January 1 3,483.7 1,706.0 535.0 23.0 Actual return on plan assets............. (348.9) 8.1 (57.1) 12.7 Company contribution..................... -- -- 37.9 43.3 GPU acquisition.......................... -- 1,901.0 -- 462.0 Benefits paid............................ (245.8) (131.4) (42.5) (6.0) ------------------------------------------------------------------------------------------- Fair value of plan assets as of December 31 ............................ 2,889.0 3,483.7 473.3 535.0 ------------------------------------------------------------------------------------------- Funded status of plan.................... (977.4) (64.2) (1,596.7) (1,046.6) Unrecognized actuarial loss.............. 1,185.8 222.8 751.6 212.8 Unrecognized prior service cost.......... 78.5 87.9 (106.8) 17.7 Unrecognized net transition obligation... -- -- 92.4 101.6 ------------------------------------------------------------------------------------------- Net amount recognized.................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) =========================================================================================== Consolidated Balance Sheets classification: Prepaid (accrued) benefit cost........... $ (548.6) $ 246.5 $ (859.5) $ (714.5) Intangible asset......................... 78.5 -- -- -- Accumulated other comprehensive loss..... 757.0 -- -- -- ------------------------------------------------------------------------------------------- Net amount recognized.................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) =========================================================================================== Company's share of net amount recognized. $ 39.3 $ (32.7) $ (117.1) $ (195.9) =========================================================================================== Assumptions used as of December 31: Discount rate............................ 6.75% 7.25% 6.75% 7.25% Expected long-term return on plan assets. 9.00% 10.25% 9.00% 10.25% Rate of compensation increase............ 3.50% 4.00% 3.50% 4.00%
FirstEnergy's net pension and other postretirement benefit costs for the three years ended December 31, 2002 were computed as follows:
Other Pension Benefits Postretirement Benefits ------------------------ ------------------------- 2002 2001 2000 2002 2001 2000 ------------------------------------------------------------------------------------------------------ (In millions) Service cost........................... $ 58.8 $ 34.9 $ 27.4 $ 28.5 $18.3 $11.3 Interest cost.......................... 249.3 133.3 104.8 113.6 64.4 45.7 Expected return on plan assets......... (346.1) (204.8) (181.0) (51.7) (9.9) (0.5) Amortization of transition obligation (asset) .................. -- (2.1) (7.9) 9.2 9.2 9.2 Amortization of prior service cost..... 9.3 8.8 5.7 3.2 3.2 3.2 Recognized net actuarial loss (gain)... -- -- (9.1) 11.2 4.9 -- Voluntary early retirement program..... -- 6.1 17.2 -- 2.3 -- ------------------------------------------------------------------------------------------------------- Net periodic benefit cost (income)..... $ (28.7) $ (23.8) $ (42.9) $114.0 $92.4 $68.9 ======================================================================================================= Company's share of net benefit cost.... $ 1.6 $ (1.9) $ (5.3) $ 9.5 $12.5 $21.3 -------------------------------------------------------------------------------------------------------
The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. (J) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily TE, OE, Penn, ATSI, FirstEnergy Solutions Corp. (FES) and FirstEnergy Service Company (FECO). The Ohio transition plan, as discussed in the "Regulatory Plan" section, resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. Unregulated operations under FES now operate the generation businesses of the Company, TE, OE and Penn. As a result, the Company entered into power supply agreements (PSA) whereby FES purchases all of the Company's nuclear generation and the generation from leased fossil generating facilities and the Company purchases its power from FES to meet its "provider of last resort" obligations. CFC serves as the transferor in connection with the accounts receivable securitization for the Company and TE. The primary affiliated companies transactions, including the effects of the PSA beginning in 2001, the sale and leaseback of the Company's transmission assets to ATSI in September 2000 and FirstEnergy's providing support services at cost, are as follows: 2002 2001 2000 - --------------------------------------------------------------------------- (In millions) Operating Revenues: PSA revenues with FES............. $283.8 $334.1 $ -- Generating units rent with FES.... 59.8 59.1 -- Ground lease with ATSI............ 7.1 7.1 4.4 Operating Expenses: Purchased power under PSA......... 420.4 597.4 -- Purchased power from TE........... 104.0 97.0 106.8 Transmission expenses (including ATSI rent)..................... 41.1 28.9 15.0 FirstEnergy support services...... 52.4 49.6 97.9 Other Income: Interest income from ATSI......... 7.2 7.2 2.4 Interest income from FES.......... 0.9 0.9 -- - --------------------------------------------------------------------------- The Company is buying 150 MW of TE's Beaver Valley Unit 2 leased capacity entitlement. Purchased power expenses for this transaction were $104.0 million, $97.0 million and $104.0 million in 2002, 2001 and 2000, respectively. This purchase is expected to continue through the end of the lease period (see Note 2). FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from its affiliates, GPU Service, Inc. and FirstEnergy Service Company, both subsidiaries of FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act (PUHCA). The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas; the ratio of each company's amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers and other factors; and specific departmental charge ratios. Management believes that these allocation methods are reasonable. (K) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Noncash financing and investing activities included capital lease transactions amounting to $2.1 million and $52.0 million in 2001 and 2000, respectively. There were no capital lease transactions in 2002. "Other amortization" on the Consolidated Statement of Cash Flows under Cash Flows from Operating Activities consists of amounts from the reduction of an electric service obligation under the Company's electric service prepayment program. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31:
2002 2001 - ---------------------------------------------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value - ---------------------------------------------------------------------------------------------------------- (In millions) Long-term debt................................... $2,309 $2,493 $2,507 $2,624 Preferred stock.................................. $ 106 $ 113 $ 125 $ 125 Investments other than cash and cash equivalents: Debt securities - Maturity (5-10 years)....................... $ 11 $ 11 $ 11 $ 11 - Maturity (more than 10 years)............... 528 576 568 565 All other..................................... 232 232 214 218 - ---------------------------------------------------------------------------------------------------------- $ 771 $ 819 $ 793 $ 794 ==========================================================================================================
The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Company's ratings. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. The Company has no securities held for trading purposes. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "All other" in the table above) consist of equity securities, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. In conjunction with the adoption of SFAS 143 on January 1, 2003, unrealized gains or losses were reclassified to other comprehensive income in accordance with SFAS 115. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized losses were approximately $6.9 million and interest and dividend income totaled approximately $7.3 million. (L) REGULATORY ASSETS- The Company recognizes, as regulatory assets, costs which the FERC and PUCO have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Company's transition plan. Based on that plan, the Company continues to bill and collect cost-based rates for its transmission and distribution services, which will remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2002 2001 - ------------------------------------------------------------------------ (In millions) Regulatory transition charge.................... $899.0 $830.3 Customer receivables for future income taxes.... 8.0 9.2 Loss on reacquired debt......................... 15.7 16.5 Other........................................... 17.1 18.5 - ------------------------------------------------------------------------ Total...................................... $939.8 $874.5 ======================================================================== 2. LEASES: The Company leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. The Company and TE sold their ownership interests in Bruce Mansfield Units 1, 2 and 3 and TE sold a portion of its ownership interest in Beaver Valley Unit 2. In connection with these sales, which were completed in 1987, the Company and TE entered into operating leases for lease terms of approximately 30 years as co-lessees. During the terms of the leases, the Company and TE continue to be responsible, to the extent of their combined ownership and leasehold interest, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company and TE have the right, at the end of the respective basic lease terms, to renew the leases. The Company and TE also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. As co-lessee with TE, the Company is also obligated for TE's lease payments. If TE is unable to make its payments under the Beaver Valley Unit 2 and Bruce Mansfield Plant leases, the Company would be obligated to make such payments. No such payments have been made on behalf of TE. (TE's future minimum lease payments as of December 31, 2002 were approximately $1.1 billion, net of trust cash receipts.) Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2002 are summarized as follows: 2002 2001 2000 - ------------------------------------------------------------------ (In millions) Operating leases Interest element...... $33.6 $35.3 $ 36.8 Other................. 42.8 36.4 29.8 Capital leases Interest element...... 0.6 3.6 5.9 Other................. 0.4 19.4 37.4 - ------------------------------------------------------------------ Total rentals......... $77.4 $94.7 $109.9 ================================================================== The future minimum lease payments as of December 31, 2002 are:
Operating Leases ------------------------------------- Capital Lease Capital Leases Payments Trust Net ---------------------------------------------------------------------------------------------- (In millions) 2003.................................. $1.0 $ 77.5 $ 79.3 $ (1.8) 2004.................................. 1.0 55.7 28.6 27.1 2005.................................. 1.0 66.7 48.3 18.4 2006.................................. 1.0 71.3 56.2 15.1 2007.................................. 1.0 57.8 48.2 9.6 Years thereafter...................... 4.7 524.7 393.3 131.4 ---------------------------------------------------------------------------------------------- Total minimum lease payments.......... 9.7 $853.7 $653.9 $199.8 ====== ====== ====== Interest portion...................... 3.3 ------------------------------------------------ Present value of net minimum lease payments...................... 6.4 Less current portion.................. 0.4 ------------------------------------------------ Noncurrent portion.................... $6.0 ================================================
The Company and TE refinanced high-cost fixed obligations related to their 1987 sale and leaseback transaction for the Bruce Mansfield Plant through a lower cost transaction in June and July 1997. In a June 1997 offering (Offering), the two companies pledged $720 million aggregate principal amount ($575 million for the Company and $145 million for TE) of first mortgage bonds due through 2007 to a trust as security for the issuance of a like principal amount of secured notes due through 2007. The obligations of the two companies under these secured notes are joint and several. Using available cash, short-term borrowings and the net proceeds from the Offering, the two companies invested $906.5 million ($569.4 million for the Company and $337.1 million for TE) in a business trust, in June 1997. The trust used these funds in July 1997 to purchase lease notes and redeem all $873.2 million aggregate principal amount of 10-1/4% and 11-1/8% secured lease obligation bonds (SLOBs) due 2003 and 2016. The SLOBs were issued by a special-purpose-funding corporation in 1988 on behalf of lessors in the two companies' 1987 sale and leaseback transaction. The Shippingport Capital Trust arrangement effectively reduces lease costs related to that transaction. 3. CAPITALIZATION: (A) RETAINED EARNINGS- There are no restrictions on retained earnings for payment of cash dividends on the Company's common stock. (B) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock-based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 2002 2001 2000 - ------------------------------------------------------------------------ Restricted common shares granted..... 36,922 133,162 208,400 Weighted average market price ....... $36.04 $35.68 $26.63 Weighted average vesting period (years) ............................ 3.2 3.7 3.8 Dividends restricted................. Yes * Yes ----------------------------------------------------------------------- * FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2002, there were 296,008 stock units outstanding. Stock option activities under the FE Programs for the past three years were as follows: Number of Weighted Average Stock Option Activities Options Exercise Price - ------------------------------------------------------------------------------ Balance, January 1, 2000.............. 2,153,369 $25.32 (159,755 options exercisable)......... 24.87 Options granted..................... 3,011,584 23.24 Options exercised................... 90,491 26.00 Options forfeited................... 52,600 22.20 Balance, December 31, 2000............ 5,021,862 24.09 (473,314 options exercisable)......... 24.11 Options granted..................... 4,240,273 28.11 Options exercised................... 694,403 24.24 Options forfeited................... 120,044 28.07 Balance, December 31, 2001............ 8,447,688 26.04 (1,828,341 options exercisable)....... 24.83 Options granted..................... 3,399,579 34.48 Options exercised................... 1,018,852 23.56 Options forfeited................... 392,929 28.19 Balance, December 31, 2002............ 10,435,486 28.95 (1,400,206 options exercisable)....... 26.07 As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans, since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair-value accounting to FirstEnergy's stock options is summarized in Note 1G - "Stock-Based Compensation." (C) PREFERRED AND PREFERENCE STOCK- The Company's preferred stock may be redeemed in whole, or in part, with 30-90 days' notice. The preferred dividend rate on the Company's Series L fluctuates based on prevailing interest rates and market conditions. The dividend rate for this issue was 7% in 2002. The Company has three million authorized and unissued shares of preference stock having no par value. (D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- The Company's $7.35 C series has an annual sinking fund requirement for 10,000 shares with annual sinking fund requirements for the next five years of $1.0 million in each year 2003-2007. (E) COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES- CFT, a wholly owned subsidiary of the Company, issued $100 million of 9% Cumulative Trust Preferred Capital Securities in December 2001. The Company purchased all of the Trust's Common Securities and simultaneously issued to the Trust $103.1 million principal amount of 9% Junior Subordinated Debentures due 2031 in exchange for the proceeds that the Trust received from its sale of Preferred and Common Securities. The sole assets of the Trust are the Subordinated Debentures whose interest and other payment dates coincide with the distribution and other payment dates on the Trust Securities. Under certain circumstances, the Subordinated Debentures could be distributed to the holders of the outstanding Trust Securities in the event the Trust is liquidated. Beginning in December 2006, the Subordinated Debentures may be optionally redeemed by the Company at a redemption price of $25 per Subordinated Debenture plus accrued interest, in which event the Trust Securities will be redeemed on a pro rata basis at $25 per share plus accumulated distributions. The Company's obligations under the Subordinated Debentures along with the related Indenture, Trust Agreement, Guarantee Agreement and the Agreement for expenses and liabilities, constitute a full and unconditional guarantee by the Company of payments due on the Preferred Securities. (F) LONG-TERM DEBT- The Company has a first mortgage indenture under which it issues from time to time first mortgage bonds secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios covenants. There also exists cross-default provisions among financing agreements of FirstEnergy and the Company. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) --------------------------------------------- 2003................................ $386.8 2004................................ 331.0 2005................................ 300.0 2006................................ -- 2007................................ 120.0 --------------------------------------------- Included in the table above are amounts for various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. These amounts are $242 million and $51 million in 2003 and 2004, respectively, which represents the next time debt holders may exercise this provision. The Company's obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of an irrevocable bank letter of credit of $48.1 million and noncancelable municipal bond insurance policies of $142.6 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letter of credit or policies, the Company is entitled to a credit against its obligation to repay that bond. The Company pays an annual fee of 1.00% of the amount of the letter of credit to the issuing bank and is obligated to reimburse the bank for any drawings thereunder. The Company and TE have unsecured letters of credit of approximately $215.9 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. The Company and TE are jointly and severally liable for the letters of credit (see Note 2). (G) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with FirstEnergy. As of December 31, 2002, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $44.1 million. 4. SHORT-TERM BORROWINGS: The Company may borrow from its affiliates on a short-term basis. As of December 31, 2002, the Company had total short-term borrowings of $288.6 million from its affiliates. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2002 and 2001, were 1.8% and 3.5%, respectively. 5. COMMITMENTS AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $312 million for property additions and improvements from 2003-2007, of which approximately $96 million is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $53 million, of which approximately $15 million applies to 2003. During the same periods, the Company's nuclear fuel investments are expected to be reduced by approximately $59 million and $28 million, respectively, as the nuclear fuel is consumed. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its ownership and leasehold interests in Beaver Valley Unit 2, the Davis-Besse Station and the Perry Plant, the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $106.3 million per incident but not more than $12.1 million in any one year for each incident. The Company is also insured as to its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $382 million of insurance coverage for replacement power costs for its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry. Under these policies, the Company can be assessed a maximum of approximately $21.4 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Company's plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs. (C) ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. In accordance with the Ohio transition plan discussed in "Regulatory Plans" in Note 1, generation operations and any related additional capital expenditures for environmental compliance are the responsibility of FirstEnergy's competitive services business unit. The Company is required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Company cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Company believes it is in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Company's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. 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 Company's Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Company's Ohio facilities by May 31, 2004. 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 Company operates affected facilities. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. 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 Company has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, 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 Company's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. The Company has total accrued liabilities aggregating approximately $2.8 million as of December 31, 2002. The effects of compliance on the Company with regard to environmental matters could have a material adverse effect on the Company's earnings and competitive position. These environmental regulations affect the Company's earnings and competitive position to the extent 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. The Company 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. (D) LEGAL MATTERS Various lawsuits, claims and proceedings related to the Company's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant applicable to the Company are described above. 6. SALE OF GENERATING ASSETS: In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 MW to NRG Energy Inc. The proposed sale had included the 376 MW Ashtabula, 1,262 MW Eastlake and 249 MW Lakeshore plants owned by the Company. On August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. 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 decided to retain ownership of these plants after reviewing other bids it subsequently received from other parties who had expressed interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, the Company reflected approximately $45 million ($26 million net of tax) of previously unrecognized depreciation and other transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statement of Income. 7. OTHER INFORMATION: The following represents the financial data which includes supplemental unaudited prior years' information as compared to consolidated financial statements and notes previously reported in 2001 and 2000:
(A) Consolidated Statements of Cash Flows 2002 2001 2000 ---- ---- ---- (In Thousands) Cash Flows from Operating Activities: Accrued taxes............................... $ (3,568) $ (48,877) $ 1,701 Accrued interest............................ (5,334) 959 (4,598) Prepayments and other....................... 27,418 27,743 (2,930) All other................................... (33,045) (89,114) (38,361) --------- --------- -------- Other cash used for operating activities.. $ (14,529) $(109,289) $(44,188) ========= ========= ======== (B) Consolidated Statements of Taxes 2002 2001 2000 ---- ---- ---- (In Thousands) Other Accumulated Deferred Income Taxes at December 31: Retirement Benefits......................... $ (42,079) $ (73,483) $(62,594) All other................................... (25,743) (51,927) 41,379 --------- --------- -------- Total-Other............................... $ (67,822) $(125,410) $(21,215) ========= ========= ========
8. RECENTLY ISSUED ACCOUNTING STANDARDS: FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002 (see Guarantees and Other Assurances). It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Company does not believe that implementation of FIN 45 will be material but the Company will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions beginning in the first interim or annual reporting period after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. The Company currently has transactions with entities which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. The Company currently consolidates the majority of these entities and believe the Company will continue to consolidate following the adoption of FIN 46. One of these entities the Company is currently consolidating is the Shippingport Capital Trust which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of our interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated parties and 0.34 percent equity interest by Toledo Edison Capital Corp., an affiliated company. 9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
March 31, June 30, September 30, December 31, Three Months Ended 2002 2002 2002 2002 - ------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues.......................... $425.0 $462.9 $538.9 $408.6 Operating Expenses and Taxes................ 369.7 350.1 410.4 380.0 - ------------------------------------------------------------------------------------------------------------- Operating Income............................ 55.3 112.8 128.5 28.6 Other Income................................ 5.2 3.4 5.6 1.8 Net Interest Charges........................ 47.8 46.8 47.3 43.3 - ------------------------------------------------------------------------------------------------------------- Net Income (Loss)........................... $ 12.7 $ 69.4 $ 86.8 $(12.9) ============================================================================================================= Earnings (Loss) Applicable to Common Stock.. $ 4.4 $ 66.3 $ 83.6 $(15.7) ============================================================================================================= March 31, June 30, September 30, December 31, Three Months Ended 2001 2001 2001 2001 - ------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues.......................... $516.4 $498.8 $603.3 $457.7 Operating Expenses and Taxes................ 463.0 420.2 430.0 367.4 - ------------------------------------------------------------------------------------------------------------- Operating Income............................ 53.4 78.6 173.3 90.3 Other Income................................ 4.4 1.1 4.0 3.7 Net Interest Charges........................ 46.2 47.2 48.4 48.0 - ------------------------------------------------------------------------------------------------------------- Net Income.................................. $ 11.6 $ 32.5 $128.9 $ 46.0 ============================================================================================================= Earnings on Common Stock.................... $ 5.1 $ 25.4 $122.6 $ 40.1 =============================================================================================================
Report of Independent Accountants To the Stockholders and Board of Directors of The Cleveland Electric Illuminating Company: In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The consolidated financial statements of The Cleveland Electric Illuminating Company and subsidiaries as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financials statements, before the revisions described in Note 1 to the 2002 consolidated financial statements, in their report dated March 18, 2002. As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for goodwill in 2002. As discussed above, the consolidated financial statements of The Cleveland Electric Illuminating Company and subsidiaries as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent accountants who have ceased operations. As described in Note 1 to the consolidated financial statements, revisions have been made to include the transitional disclosures required by Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, which was adopted by the Company as of January 1, 2002. In our opinion the transitional disclosures for 2001 and 2000 are appropriate. However, we were not engaged to audit, review, or apply any procedures to the 2001 and 2000 consolidated financial statements of the Company other than with respect to such disclosures and, accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 consolidated financial statements taken as a whole. PricewaterhouseCoopers LLP Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. Report of Independent Public Accountants To the Stockholders and Board of Directors of The Cleveland Electric Illuminating Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Cleveland Electric Illuminating Company (an Ohio corporation and wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. EX-21 22 cei_ex21-2.txt EX. 21-2 LIST OF SUBS - CEI EXHIBIT 21.2 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY LIST OF SUBSIDIARIES OF THE REGISTRANT AT DECEMBER 31, 2002 Centerior Funding Corporation - Incorporated in Delaware Cleveland Electric Financing Trust I - Incorporated in Delaware Statement of Differences ------------------------ Exhibit Number 21, List of Subsidiaries of the Registrant at December 31, 2002, is not included in the printed document. EX-4 23 te_ex4-3.txt EX. 4-3 SUPPLEMENTAL INDENTURE (52ND) - TE =============================================================================== THE TOLEDO EDISON COMPANY TO JPMORGAN CHASE BANK (FORMERLY KNOWN AS THE CHASE MANHATTAN BANK) Trustee. ----------------- Fifty-second Supplemental Indenture Dated as of October 1, 2002 ----------------- (Supplemental to Indenture dated as of April 1, 1947) ----------------- First Mortgage Bonds, Pledge Series A of 2002 due 2033 =============================================================================== FIFTY-SECOND SUPPLEMENTAL INDENTURE, dated as of October 1, 2002, between THE TOLEDO EDISON COMPANY, a corporation organized and existing under the laws of the State of Ohio (hereinafter called the "Company"), and JPMORGAN CHASE BANK (formerly known as THE CHASE MANHATTAN BANK), a corporation existing under the laws of the State of New York (hereinafter called the "Trustee"), as Trustee. RECITALS The Company has heretofore executed and delivered an Indenture of Mortgage and Deed of Trust dated as of April 1, 1947 (hereinafter referred to as the "Original Indenture") to The Chase National Bank of the City of New York, predecessor Trustee, to secure an issue of First Mortgage Bonds of the Company, issuable in series, and created thereunder an initial series of bonds designated as First Mortgage Bonds, 2?% Series due 1977; and The Company has heretofore executed and delivered to The Chase National Bank of the City of New York, predecessor Trustee, four Supplemental Indentures supplementing the Original Indenture dated, respectively, September 1, 1948, April 1, 1949, December 1, 1950 and March 1, 1954 and has heretofore executed and delivered to The Chase Manhattan Bank, which on March 31, 1955, became the Trustee under the Original Indenture by virtue of the merger of The Chase National Bank of the City of New York into President and Directors of The Manhattan Company under the name of The Chase Manhattan Bank, the Fifth and the Sixth Supplemental Indentures dated, respectively, February 1, 1956, and May 1, 1958, supplementing the Original Indenture; and The Chase Manhattan Bank was converted into a national banking association under the name The Chase Manhattan Bank (National Association), effective September 23, 1965; and by virtue of said conversion the continuity of the business of The Chase Manhattan Bank, including its business of acting as corporate trustee, and its corporate existence, was not affected, so that The Chase Manhattan Bank (National Association) was vested with all the trusts, powers, discretion, immunities, privileges and all other matters as were vested in said The Chase Manhattan Bank under the Indenture (hereinafter defined), with like effect as if originally named as Trustee therein; and The Company has heretofore executed and delivered to The Chase Manhattan Bank (National Association) forty-one Supplemental Indentures dated, respectively, as follows: Seventh, August 1, 1967, Eighth, November 1, 1970, Ninth, August 1, 1972, Tenth, November 1, 1973, Eleventh, July 1, 1974, Twelfth, October 1, 1975, Thirteenth, June 1, 1976, Fourteenth, October 1, 1978, Fifteenth, September 1, 1979, Sixteenth, September 1, 1980, Seventeenth, October 1, 1980, Eighteenth, April 1, 1981, Nineteenth, November 1, 1981, Twentieth, June 1, 1982, Twenty-first, September 1, 1982, Twenty-second, April 1, 1983, Twenty-third, December 1, 1983, Twenty-fourth, April 1, 1984, Twenty-fifth, October 15, 1984, Twenty-sixth, October 15, 1984, Twenty-seventh, August 1, 1985, Twenty-eighth, August 1, 1985, Twenty-ninth, December 1, 1985, Thirtieth, March 1, 1986, Thirty-first, October 15, 1987, Thirty-second, September 15, 1988, Thirty-third, June 15, 1989, Thirty-fourth, October 15, 1989, Thirty-fifth, May 15, 1990, Thirty-sixth, March 1, 1991, Thirty-seventh, May 1, 1992, Thirty-eighth, August 1, 1992, Thirty-ninth, October 1, 1992, Fortieth, January 1, 1993, Forty-first, September 15, 1994, Forty-second, May 1, 1995, Forty-third, June 1, 1995, Forty-fourth, July 14, 1995, Forty-fifth, July 15, 1995, Forty-sixth, June 15, 1997 and Forty-seventh, August 1, 1997 supplementing the Original Indenture; and The Chase Manhattan Bank (National Association), Successor Trustee, was merged on July 1, 1996, with and into Chemical Bank, a New York banking corporation, which changed its name to The Chase Manhattan Bank, and which became the Trustee under the Original Indenture by virtue of such merger; and The Company has heretofore executed and delivered to The Chase Manhattan Bank four Supplemental Indentures dated as follows: Forty-eighth, June 1, 1998, Forty-ninth, January 15, 2000, Fiftieth, May 1, 2000 and Fifty-first, September 1, 2000 supplementary to the Original Indenture (the Original Indenture, all the aforementioned Supplemental Indentures, this Fifty-second Supplemental Indenture and any other indentures supplemental to the Original Indenture are herein collectively called the "Indenture" and this Fifty-second Supplemental Indenture is hereinafter called this "Supplemental Indenture"); and The Chase Manhattan Bank changed its name to JPMorgan Chase Bank on November 10, 2001; and The Company covenanted in and by the Original Indenture to execute and deliver such further instruments and do such further acts as may be necessary or proper to carry out more effectually the purposes of the Original Indenture and to make subject to the lien thereof property acquired after the execution and delivery of the Original Indenture; and Under Article 3 of the Original Indenture, the Company is authorized to issue additional bonds upon the terms and conditions expressed in the Original Indenture; and The Company proposes to create a new series of First Mortgage Bonds to be designated as First Mortgage Bonds, Pledge Series A of 2002 due 2033 (hereinafter called the "Bonds of 2002 Pledge Series A") with the denominations, rates of interest, date of maturity, redemption provisions and other provisions and agreements in respect thereof as in this Supplemental Indenture set forth; and The Bonds of 2002 Pledge Series A are to be issued by the Company and delivered to Ambac Assurance Corporation, a Wisconsin-domiciled stock insurance corporation (the "Insurer") pursuant to an Insurance Agreement, dated as of October 1, 2002 (the "Insurance Agreement"), between the Company and the Insurer under which (i) the Insurer has agreed to issue a municipal bond insurance policy (the "Policy") insuring the payment of the principal of and interest on, and for the benefit of the holders of, $20,200,000 aggregate principal amount of the State of Ohio Pollution Control Revenue Refunding Bonds, Series 2002-A (The Toledo Edision Company Project) (the "Authority Bonds") to be issued by the Ohio Air Quality Development Authority (the "Authority") and (ii) the Company has agreed to deliver to the Insurer a series of its first mortgage bonds as security for the Company's obligation to reimburse the Insurer in respect of payments made by the Insurer under the Policy; and The Company, by appropriate corporate action, has duly resolved and determined to execute this Supplemental Indenture for the purpose of providing for the creation of the Bonds of 2 2002 Pledge Series A and of specifying the form, provisions and particulars thereof as in said Original Indenture, as amended, provided or permitted, including the issuance only of fully registered bonds, and of giving to the Bonds of 2002 Pledge Series A the protection and security of the Indenture; and The text of the Bonds of 2002 Pledge Series A is to be substantially in the following respective forms: [FORM OF FULLY REGISTERED BOND OF 2002 PLEDGE SERIES A] THIS BOND IS NOT TRANSFERABLE EXCEPT TO A SUCCESSOR TO AMBAC ASSURANCE CORPORATION (THE "INSURER") UNDER THE INSURANCE AGREEMENT, DATED AS OF OCTOBER 1, 2002, BETWEEN THE COMPANY AND AMBAC ASSURANCE CORPORATION, AS AMENDED OR SUPPLEMENTED (THE "INSURANCE AGREEMENT"), OR IN COMPLIANCE WITH A FINAL ORDER OF A COURT OF COMPETENT JURISDICTION IN CONNECTION WITH ANY BANKRUPTCY OR REORGANIZATION PROCEEDING OF THE COMPANY. THE TOLEDO EDISON COMPANY FIRST MORTGAGE BOND, PLEDGE SERIES A OF 2002 DUE 2033 No. $__________ THE TOLEDO EDISON COMPANY, an Ohio corporation (hereinafter called the Company), for value received, hereby promises to pay to _________________________________, or registered assigns, the principal sum of _______________________ dollars ($_________) or the aggregate unpaid principal amount hereof, whichever is less, on September 1, 2033, in any coin or currency of the United States of America which at the time of such payment shall be legal tender for the payment of public and private debts, and to pay interest on the unpaid principal amount hereof in like coin or currency to the registered owner hereof at such rate per annum on each interest payment date (hereinafter defined) as shall cause the amount of interest payable on such interest payment date on the Bonds of this Series (hereinafter defined) to equal the amount of interest payable on such interest payment date on the Authority Bonds (hereinafter defined). Such interest shall be payable on the same dates as interest is payable on said Authority Bonds (each such date hereinafter called an "interest payment date"), until maturity or redemption of this Bond, or, if the Company shall default in the payment of the principal due on this Bond, until the Company's obligation with respect to the payment of such principal shall be discharged as provided in the Indenture (hereinafter defined). The amount of interest payable on each interest payment date shall be computed on the same basis as the corresponding amount is computed on the Authority Bonds, provided, however, that the aggregate amount of interest payable on any interest payment date shall not exceed an amount which results in an interest rate of more than 10% per annum on the aggregate principal amount of the Bonds of this Series outstanding from time to time. Except as hereinafter provided, this Bond shall bear interest (a) from the interest payment date next preceding the date of this Bond to which interest has been paid, or (b) if the date of this 3 Bond is an interest payment date to which interest has been paid, then from such date, or (c) if no interest has been paid on this Bond, then from the date of initial issue. This Bond is one of the Bonds of the Company, known as its First Mortgage Bonds, issued and to be issued in one or more series under and equally and ratably secured (except as any sinking, amortization, improvement or other fund, established in accordance with the provisions of said Indenture, may afford additional security for the Bonds of any particular series) by a certain Indenture of Mortgage and Deed of Trust, dated as of April 1, 1947 (hereinafter called the "Original Indenture"), made by the Company to The Chase National Bank of the City of New York (JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank), successor), as Trustee (hereinafter called the "Trustee"), and by certain indentures supplemental thereto, including the Fifty-second Supplemental Indenture dated as of October 1, 2002 (the Original Indenture and said indentures supplemental thereto herein collectively called the "Indenture" and said Fifty-second Supplemental Indenture hereinafter called the "Supplemental Indenture"), to which Indenture reference is hereby made for a description of the property mortgaged, the nature and extent of the security, the rights and limitations of rights of the Company, the Trustee and the holders of said Bonds and of the coupons appurtenant to coupon Bonds under the Indenture and the terms and conditions upon which said Bonds are and are to be issued and secured, to all of the provisions of which Indenture and of all such supplemental indentures in respect of such security, including the provisions of the Indenture permitting the issue of Bonds of any series for property which, under the restrictions and limitations therein specified, may be subject to liens prior to the lien of the Indenture, the holder, by accepting this Bond, assents. To the extent permitted by and as provided in the Indenture, the rights and obligations of the Company and of the holders of said Bonds and coupons (including those pertaining to any sinking or other fund) may be changed and modified, with the consent of the Company, by the holders of at least 75% in aggregate principal amount of the Bonds then outstanding, such percentage being determined as provided in the Indenture; provided, however, that in case such changes and modifications affect one or more but less than all series of Bonds then outstanding, they shall be required to be adopted only by the affirmative vote of the holders of at least 75% in aggregate principal amount of outstanding Bonds of such one or more series so affected; and further provided, that without the consent of the holder hereof no such change or modification shall be made which will extend the time of payment of the principal of, or of the interest or premium, if any, on this Bond or reduce the principal amount hereof or the rate of interest or the premium, if any, hereon, or affect any other modification of the terms of payment of such principal or interest or premium, if any, or will permit the creation of any lien ranking prior to or on a parity with the lien of the Indenture on any of the mortgaged property, or will deprive the holder hereof of the benefit of a lien upon the mortgaged property for the security of this Bond, or will reduce the percentage of Bonds required for the adoption of changes or modifications as aforesaid. This Bond is one of a series of Bonds designated as the First Mortgage Bonds, Pledge Series A of 2002 due 2033, of the Company (herein called the "Bonds of this Series") limited, except as otherwise provided in the Indenture, in aggregate principal amount to $20,200,000, and is issued under and secured by the Supplemental Indenture. The Bonds of this Series have been issued by the Company to Ambac Assurance Corporation, a Wisconsin-domiciled stock insurance corporation (the "Insurer"), to (i) provide 4 for the payment of the Company's obligations to make payments to the Insurer under an Insurance Agreement, dated as of October 1, 2002 (the "Insurance Agreement"), between the Company and the Insurer, and (ii) provide to the Insurer the benefits of the security provided for the Bonds of this Series. The Insurance Agreement has been entered into by the Company in connection with the issuance by the Insurer of a municipal bond insurance policy (the "Policy") insuring the payment of the principal of and interest on, and for the benefit of the holders of, $20,200,000 aggregate principal amount of the State of Ohio Pollution Control Revenue Refunding Bonds, Series 2002-A (The Toledo Edison Company Project) (the "Authority Bonds") issued on behalf of the Company by the Ohio Air Quality Development Authority (the "Authority") and under the Trust Indenture, dated as of October 1, 2002 (the "Authority Bond Indenture"), between the Authority and The Bank of New York, as trustee (such trustee and any successor trustee being hereinafter referred to as the "Authority Bond Trustee"). Payments made by the Company of principal and interest on the Bonds of this Series are intended to be sufficient to reimburse the Insurer for any payments of principal and interest made by the Insurer on the Authority Bonds pursuant to the Policy. The Bonds of this Series are not transferable except (i) as required to effect an assignment to a successor of the Insurer under the Insurance Agreement or (ii) in compliance with a final order of a court of competent jurisdiction in connection with any bankruptcy or reorganization proceeding of the Company. The Company's obligation to make payments with respect to the principal of and/or interest on the Bonds of this Series shall be fully or partially satisfied and discharged to the extent that, at the time any such payment shall be due, the corresponding amount then due of principal of and/or interest on the Authority Bonds shall have been fully or partially paid (other than by the application of the proceeds of any payment by the Insurer under the Policy), as the case may be, or there shall have been deposited with the Authority Bond Trustee pursuant to the Authority Bond Indenture trust funds sufficient to fully or partially pay, as the case may be, the corresponding amount then due of principal of and/or interest on the Authority Bonds (other than by the application of the proceeds of any payment by the Insurer under the Policy). Notwithstanding anything contained herein or in the Indenture to the contrary, the Company shall be obligated to make payments with respect to the principal of and/or interest on the Bonds of this Series only to the extent that the Insurer has made a payment with respect to the Authority Bonds under the Policy. Upon payment of the principal of and interest due on the Authority Bonds, whether at maturity or prior to maturity by acceleration, redemption or otherwise, or upon provision for the payment thereof having been made in accordance with the Authority Bond Indenture (other than by the application of the proceeds of any payment by the Insurer under the Policy), the Bonds of this Series in a principal amount equal to the principal amount of Authority Bonds so paid or for which such provision for payment has been made shall be deemed fully paid, satisfied and discharged and the obligations of the Company thereunder shall be terminated and such Bonds of this Series shall be surrendered to and canceled by the Trustee. From and after the Release Date (as defined in the Insurance Agreement), the Bonds of this Series shall be deemed fully paid, satisfied and discharged and the obligation of the Company thereunder shall be terminated. On the Release Date, the Bonds of this Series shall be surrendered to and canceled by the Trustee. 5 The Bonds of this Series are subject to mandatory redemption, in whole or in part, as the case may be, on each date that Authority Bonds are to be redeemed. The principal amount of the Bonds of this Series to be redeemed on any such date shall be equal to the principal amount of Authority Bonds called for redemption on that date. All redemptions of Bonds of this Series shall be at 100% of the principal amount thereof, plus accrued interest to the redemption date. The principal of this Bond may be declared or may become due before the maturity hereof, on the conditions, in the manner and at the times set forth in the Indenture, upon the happening of a default as therein defined. No recourse under or upon any covenant or obligation of the Indenture, or of any indenture supplemental thereto, or of this Bond, for the payment of the principal of or the interest on this Bond, or for any claim based thereon, or otherwise in any manner in respect thereof, shall be had against any incorporator, subscriber to the capital stock, stockholder, officer or director, as such, of the Company, whether former, present or future, either directly or indirectly through the Company or any predecessor or successor corporation or the Trustee, by the enforcement of any subscription to capital stock, assessment or otherwise, or by any legal or equitable proceeding by virtue of any constitution, statute, or otherwise (including, without limiting the generality of the foregoing, any proceeding to enforce any claimed liability of stockholders of the Company based upon any theory of disregarding the corporate entity of the Company or upon any theory that the Company was acting as the agent or instrumentality of the stockholders), any and all such liability of incorporators, stockholders, subscribers, officers and directors, as such, being released by the holder hereof, by the acceptance of this Bond, and being likewise waived and released by the terms of the Indenture. This Bond shall not be valid or become obligatory for any purpose until the certificate of authentication endorsed hereon shall have been signed by JPMorgan Chase Bank or its successor, as Trustee under the Indenture. IN WITNESS WHEREOF, THE TOLEDO EDISON COMPANY has caused this Bond to be signed in its name by its President or a Vice-President and its corporate seal to be impressed or imprinted hereon and attested by its Corporate Secretary or an Assistant Corporate Secretary. Dated THE TOLEDO EDISON COMPANY By -------------------------------------------- Vice President Attest: - ------------------------------------ Corporate Secretary 6 [FORM OF TRUSTEE'S CERTIFICATE OF AUTHENTICATION] This Bond is one of the Bonds of the series designated herein, described in the within-mentioned Indenture. JPMORGAN CHASE BANK, AS TRUSTEE By --------------------------------------------------- Authorized Officer [END OF FORM OF BOND OF 2002 PLEDGE SERIES A] All conditions and requirements necessary to make this Supplemental Indenture a valid, legal and binding instrument in accordance with its terms and to make the Bonds of 2002 Pledge Series A, when duly executed by the Company and authenticated and delivered by the Trustee, and duly issued, the valid, binding and legal obligations of the Company, have been done and performed, and the execution and delivery of this Supplemental Indenture have been in all respects duly authorized. NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH: That The Toledo Edison Company, the Company herein named, in consideration of the premises and of One Dollar ($1.00) to it duly paid by the Trustee at or before the ensealing and delivery of these presents, the receipt whereof is hereby acknowledged, does hereby covenant and agree to and with the Trustee and its successors in the trust under the Indenture, for the benefit of those who shall hold the bonds to be issued hereunder and thereunder, as hereinafter provided, as follows: ARTICLE I CREATION AND DESCRIPTION OF BONDS OF 2002 PLEDGE SERIES A SECTION 1. A new series of bonds to be issued under and secured by the Indenture is hereby created, to be designated as "First Mortgage Bonds, Pledge Series A of 2002 due 2033" (such bonds herein referred to as the "Bonds of 2002 Pledge Series A"). The Bonds of 2002 Pledge Series A shall be limited to an aggregate principal amount of $20,200,000. The Bonds of 2002 Pledge Series A shall be substantially in the form hereinbefore recited. SECTION 2. The principal of all Bonds of 2002 Pledge Series A shall be payable on September 1, 2033, unless earlier redeemed, and shall bear interest from the time hereinafter provided at such rate per annum on each interest payment date (hereinafter defined) as shall cause the amount of interest payable on each interest payment date on the Bonds of 2002 Pledge Series A to equal the amount of interest payable on such interest payment date on the Authority 7 Bonds. Such interest shall be payable on the same dates as interest is payable on the Authority Bonds (each such date herein called an "interest payment date"), until the maturity or redemption of the Bonds of 2002 Pledge Series A, or, in the case of any default by the Company in the payment of the principal due on any such Bonds, until the Company's obligation with respect to the payment of such principal shall be discharged as provided in the Indenture. The amount of interest payable on each interest payment date shall be computed on the same basis as the corresponding amount is computed on the Authority Bonds, provided, however, that the aggregate amount of interest payable on any interest payment date shall not exceed an amount which results in an interest rate of more than 10% per annum on the aggregate principal amount of the Bonds of 2002 Pledge Series A outstanding from time to time. Except as hereinafter provided, each Bond of 2002 Pledge Series A shall bear interest (a) from the interest payment date next preceding the date of such Bond to which interest has been paid, or (b) if the date of such Bond is an interest payment date to which interest has been paid, then from such date, or (c) if no interest has been paid thereon, then from the date of initial issue. The Trustee may rely upon the certification of the Insurer of the interest rate of, interest payment dates of and basis on which interest is computed for, the Authority Bonds as necessary to enable the Trustee to determine for the Bonds of 2002 Pledge Series A their corresponding interest rate, interest payment dates and basis on which interest shall be computed and with respect to its payments under the Policy. SECTION 3. The Bonds of 2002 Pledge Series A shall be payable as to principal and interest at the office or agency of the Company in the Borough of Manhattan, The City of New York; and principal and interest shall be payable in any coin or currency of the United States of America which at the time of payment shall be legal tender for the payment of public and private debts. SECTION 4. The Bonds of 2002 Pledge Series A shall be issued only as fully registered Bonds in the denominations of $1,000 or any higher multiple of $1.00. SECTION 5. Except as may be necessary to comply with a final order of a court of competent jurisdiction in connection with any bankruptcy or reorganization proceeding of the Company, the Bonds of 2002 Pledge Series A shall be transferable only to a successor to Ambac Assurance Corporation under the Insurance Agreement in the manner and upon the terms set forth in ss. 2.05 of the Original Indenture, but notwithstanding the provisions of ss. 2.08 of the Original Indenture, no charge shall be made upon any transfer or exchange of Bonds of 2002 Pledge Series A other than for any tax or taxes or other governmental charge required to be paid by the Company. SECTION 6. The Company's obligation to pay the principal of or interest on the Bonds of 2002 Pledge Series A, shall be fully or partially satisfied as stated in the form of the Bonds of the 2002 Pledge Series A hereinbefore recited. SECTION 7. The Bonds of 2002 Pledge Series A may be executed by the Company and delivered to the Trustee and, upon compliance with all applicable provisions and requirements of the Original Indenture in respect thereof, shall be authenticated by the Trustee 8 and delivered (without awaiting the filing or recording of this Supplemental Indenture) in accordance with the written order or orders of the Company. SECTION 8. The Bonds of 2002 Pledge Series A shall be redeemed by the Company in whole or in part at any time prior to maturity at a redemption price of 100% of the principal amount to be redeemed, plus any accrued and unpaid interest to the redemption date as stated in the form of the Bonds of the 2002 Pledge Series A hereinbefore recited. ARTICLE II THE TRUSTEE The Trustee accepts the trusts created by this Supplemental Indenture upon the terms and conditions in the Original Indenture and in this Supplemental Indenture set forth. The recitals in this Supplemental Indenture are made by the Company only and not by the Trustee. Each and every term and condition contained in Article 13 of the Original Indenture shall apply to this Supplemental Indenture with the same force and effect as if the same were herein set forth in full, with such omissions, variations and modifications thereof as may be appropriate to make the same conform to this Supplemental Indenture. For purposes of this Supplemental Indenture (a) the Trustee may conclusively rely and shall be protected in acting upon a written certificate of the Insurer as to the interest rate of, interest payment dates of and basis on which interest is computed for, the Authority Bonds and with respect to payments under the Authority Bonds, its payments under the Policy and the occurrence of the Release Date, or any officer's certificate or opinion of counsel, as to the truth of the statements and the correctness of the opinions expressed therein, without independent investigation or verification thereof, subject to Article 13 of the Indenture, (b) a written certificate of the Insurer shall mean a written certificate executed by the president, any vice president or any authorized officer of the Insurer and (c) in the absence of a written certificate of the Insurer with respect to its payments under the Policy, the Trustee may conclusively assume that no such payments have been made. ARTICLE III MISCELLANEOUS PROVISIONS SECTION 1. The Original Indenture, as heretofore supplemented, is in all respects ratified and confirmed, and the Original Indenture, this Supplemental Indenture and all other indentures supplemental to the Original Indenture shall be read, taken and construed as one and the same instrument. Neither the execution of this Supplemental Indenture nor anything herein contained shall be construed to impair the lien of the Indenture on any of the property subject thereto, and such lien shall remain in full force and effect as security for all bonds now outstanding or hereafter issued under the Indenture. All covenants and provisions of the Original Indenture, except as modified by this Supplemental Indenture and all other indentures supplemental to the Original Indenture, shall continue in full force and effect for the respective periods of time therein specified, and this Supplemental Indenture shall form part of the 9 Indenture. All terms defined in Article 1 of the Original Indenture shall, for all purposes of this Supplemental Indenture, have the meanings in said Article 1 specified, except as modified by this Supplemental Indenture and all other indentures supplemental to the Original Indenture and unless the context otherwise requires. SECTION 2. This Supplemental Indenture may be simultaneously executed in any number of counterparts, and all said counterparts executed and delivered, each as an original, shall constitute but one and the same instrument. IN WITNESS WHEREOF, The Toledo Edison Company has caused its corporate name to be hereunto affixed and this instrument to be signed by its President or a Vice President and its corporate seal to be hereunto affixed and attested by its Corporate Secretary or an Assistant Corporate Secretary for and in its behalf and JPMorgan Chase Bank, as Trustee, in evidence of its acceptance of the trust hereby created, has caused its corporate name to be hereunto affixed, this instrument to be signed by its President or a Vice President and its corporate seal to be hereunto affixed and attested by its Secretary or an Assistant Secretary or any other authorized officer for and on its behalf, all as of the day and year first above written. 10 THE TOLEDO EDISON COMPANY By -------------------------------------------------- Richard H. Marsh, Senior Vice President and Chief Financial Officer [SEAL] Attest: ----------------------------------------- Nancy C. Ashcom, Corporate Secretary Signed, sealed and acknowledged on behalf of THE TOLEDO EDISON COMPANY in the presence of ----------------------------------------- Michael J. Sulhan ----------------------------------------- Julie A. Phillips As witnesses JPMORGAN CHASE BANK, AS TRUSTEE By ------------------------------------------------------- __________________, Vice President Attest: ----------------------------------------- ____________________, Trust Officer Signed, sealed and acknowledged on behalf of JPMORGAN CHASE BANK in the presence of ----------------------------------- [SEAL] Print Name: ----------------------------------- Print Name: As witnesses STATE OF OHIO ) ) ss.: COUNTY OF SUMMIT ) On this 8th day of October, 2002, before me personally appeared Richard H. Marsh and Nancy C. Ashcom to me personally known, who being by me severally duly sworn, did say that they are a Senior Vice President and Chief Financial Officer and the Corporate Secretary, respectively, of The Toledo Edison Company, that the seal affixed to the foregoing instrument is the corporate seal of said corporation and that said instrument was signed and sealed in behalf of said corporation by authority of its Board of Directors; and said officers severally acknowledged said instrument to be the free act and deed of said corporation. --------------------------------------- [SEAL] Susie M. Hoisten, Notary Public Residence - Summit County State Wide Jurisdiction, Ohio My Commission Expires December 9, 2006 STATE OF NEW YORK ) ) ss.: COUNTY OF NEW YORK ) On this 8th day of October, 2002 before me personally appeared ____________ and _____________ to me personally known, who being by me severally duly sworn, did say that they are a Vice President and a Trust Officer, respectively, of JPMorgan Chase Bank, that the seal affixed to the foregoing instrument is the corporate seal of said Corporation and that said instrument was signed and sealed in behalf of said a Corporation by authority of its Board of Directors; and said officers severally acknowledged said instrument to be the free act and deed of said Corporation. ------------------------------------ [SEAL] Notary Public This instrument was prepared by: FirstEnergy Corp. 76 South Main Street Akron, Ohio 44308 EX-12 24 te_ex12-4.txt EX. 12-4 FIXED CHARGE RATIO - TE EXHIBIT 12.4 Page 1 THE TOLEDO EDISON COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
Year Ended December 31, ----------------------------------------------------------- 1998 1999 2000 2001 2002 ---------- ---------- ---------- --------- --------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items......................... $106,582 $ 99,945 $137,233 $ 62,911 $ 13,337 Interest and other charges, before reduction for amounts capitalized..................................... 88,263 78,496 72,055 62,283 57,672 Provision for income taxes................................ 72,696 56,821 76,991 39,642 4,907 Interest element of rentals charged to income (a)......... 100,245 98,445 96,358 92,108 87,174 -------- -------- -------- -------- -------- Earnings as defined..................................... $367,786 $333,707 $382,637 $256,944 $163,090 ======== ======== ======== ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K: Interest expense.......................................... $ 88,263 $ 78,496 $ 72,055 $ 62,283 $ 57,672 Interest element of rentals charged to income (a)......... 100,245 98,445 96,358 92,108 87,174 -------- -------- -------- -------- -------- Fixed charges as defined................................ $188,508 $176,941 $168,413 $154,391 $144,846 ======== ======== ======== ======== ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES................................................... 1.95 1.89 2.27 1.66 1.13 ==== ==== ==== ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
EXHIBIT 12.4 Page 2 THE TOLEDO EDISON COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
Year Ended December 31, ------------------------------------------------------------- 1998 1999 2000 2001 2002 ---------- ---------- ---------- --------- --------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items............................ $106,582 $ 99,945 $137,233 $ 62,911 $ 13,337 Interest and other charges, before reduction for amounts capitalized.................................... 88,263 78,496 72,055 62,283 57,672 Provision for income taxes................................... 72,696 56,821 76,991 39,642 4,907 Interest element of rentals charged to income (a)............ 100,245 98,445 96,358 92,108 87,174 --------- ---------- -------- -------- -------- Earnings as defined........................................ $367,786 $333,707 $382,637 $256,944 $163,090 ======== ======== ======== ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS): Interest expense............................................. $ 88,263 $ 78,496 $ 72,055 $ 62,283 $ 57,672 Preferred stock dividend requirements........................ 13,609 16,238 16,247 16,135 11,356 Adjustments to preferred stock dividends to state on a pre-income tax basis......................... 8,335 10,363 10,143 10,167 4,178 Interest element of rentals charged to income (a)............ 100,245 98,445 96,358 92,108 87,174 --------- ---------- -------- -------- -------- Fixed charges as defined plus preferred stock dividend requirements (pre-income tax basis)............. $210,452 $203,542 $194,803 $180,693 $160,380 ======== ======== ======== ======== ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)....................................... 1.75 1.64 1.96 1.42 1.02 ==== ==== ==== ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
EX-13 25 te_ex13-3.txt EX. 13.3 ANNUAL REPORT - TE _ THE TOLEDO EDISON COMPANY 2002 ANNUAL REPORT TO STOCKHOLDERS The Toledo Edison Company (TE) is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the generation, distribution and sale of electric energy in an area of approximately 2,500 square miles in northwestern Ohio. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 0.8 million. Contents Page - -------- ---- Selected Financial Data............................................ 1 Management's Discussion and Analysis............................... 2-12 Consolidated Statements of Income.................................. 13 Consolidated Balance Sheets........................................ 14 Consolidated Statements of Capitalization.......................... 15-16 Consolidated Statements of Common Stockholder's Equity............. 17 Consolidated Statements of Preferred Stock......................... 17 Consolidated Statements of Cash Flows.............................. 18 Consolidated Statements of Taxes................................... 19 Notes to Consolidated Financial Statements......................... 20-33 Reports of Independent Accountants................................. 34-35
THE TOLEDO EDISON COMPANY SELECTED FINANCIAL DATA 2002 2001 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- (Dollars in thousands) GENERAL FINANCIAL INFORMATION: Operating Revenues...................... $ 987,645 $1,094,903 $ 954,947 $ 921,159 $ 957,037 ========== ========== ========== ========== ========== Operating Income........................ $ 55,178 $ 105,484 $ 193,414 $ 163,772 $ 180,261 ========== ========== ========== ========== ========== Net Income.............................. $ 13,337 $ 62,911 $ 137,233 $ 99,945 $ 106,582 ========== ========== ========== ========== ========== Earnings on Common Stock................ $ 1,981 $ 46,776 $ 120,986 $ 83,707 $ 92,972 ========== ========== ========== ========== ========== Total Assets............................ $2,617,224 $2,572,118 $2,652,267 $2,666,928 $2,768,765 ========== ========== ========== ========== ========== CAPITALIZATION: Common Stockholder's Equity............. $ 712,931 $ 637,665 $ 605,587 $ 551,704 $ 575,692 Preferred Stock Not Subject to Mandatory Redemption.................. 126,000 126,000 210,000 210,000 210,000 Long-Term Debt.......................... 557,265 646,174 944,193 981,029 1,083,666 ---------- ---------- ---------- ---------- ---------- Total Capitalization.................. . $1,396,196 $1,409,839 $1,759,780 $1,742,733 $1,869,358 ========== ========== ========== ========== ========== CAPITALIZATION RATIOS: Common Stockholder's Equity............. 51.1% 45.2% 34.4% 31.7% 30.8% Preferred Stock Not Subject to Mandatory Redemption.................. 9.0 9.0 11.9 12.0 11.2 Long-Term Debt.......................... 39.9 45.8 53.7 56.3 58.0 ----- ----- ------ ----- ----- Total Capitalization.................... 100.0% 100.0% 100.0% 100.0% 100.0% ===== ===== ===== ===== ===== DISTRIBUTION KILOWATT-HOUR DELIVERIES (Millions): Residential............................. 2,427 2,258 2,183 2,127 2,252 Commercial.............................. 2,702 2,667 2,380 2,236 2,425 Industrial.............................. 5,280 5,397 5,595 5,449 5,317 Other................................... 57 61 49 54 63 ------ ------ ------ ------ ------ Total................................... 10,466 10,383 10,207 9,866 10,057 ====== ====== ====== ====== ====== CUSTOMERS SERVED: Residential............................. 272,474 270,589 269,071 266,900 265,237 Commercial.............................. 32,037 31,680 31,413 32,481 31,982 Industrial.............................. 1,883 1,898 1,917 1,937 1,954 Other................................... 468 443 598 398 359 ------- ------- ------- ------- ------- Total................................... 306,862 304,610 302,999 301,716 299,532 ======= ======= ======= ======= ======= Number of Employees .................... 508 507 539 977 997
THE TOLEDO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Corporate Separation - -------------------- Beginning on January 1, 2001, Ohio customers were able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. That legislation required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Toledo Edison Company (TE) continues to deliver power to homes and businesses through our existing distribution system and maintain the "provider of last resort" (PLR) obligation under our rate plan. As a result of the transition plan, FirstEnergy's electric utility operating companies (EUOC) entered into power supply agreements whereby FirstEnergy Solutions Corp. (FES) purchases all of the EUOC nuclear generation, and leases EUOC fossil generating facilities. We are a "full requirements" customer of FES to enable us to meet our PLR responsibilities in our service area. The effect on TE's reported results of operations during 2001 from FirstEnergy's corporate separation plan and our sale of transmission assets to American Transmission Systems, Inc. (ATSI) in September 2000, are summarized in the following tables: Corporate Restructuring - 2001 Income Statement Effects ------------------------------------------------------- Increase (Decrease)
Corporate Separation ATSI Total ---------- ---- ----- (In millions) Operating Revenues: Power supply agreement with FES........ $180.9 $-- $180.9 Generating units rent.................. 14.0 -- 14.0 Ground lease with ATSI................. -- (0.2) (0.2) ---------------------------------------------------------------------------------------- Total Operating Revenues Effect........ $194.9 $(0.2) $194.7 ======================================================================================== Operating Expenses and Taxes: Fossil fuel costs...................... $(39.8)(a) $-- $(39.8) Purchased power costs.................. 388.0 (b) -- 388.0 Other operating costs.................. (21.6)(a) 7.6 (d) (14.0) Provision for depreciation and amortization ......................... -- (2.7)(e) (2.7) General taxes.......................... (2.0)(c) (3.3)(e) (5.3) Income taxes........................... (50.4) 0.1 (50.3) ---------------------------------------------------------------------------------------- Total Operating Expenses Effect........ $274.2 $ 1.7 $275.9 ======================================================================================== Other Income............................. $ -- $ 2.0 (f) $ 2.0 ======================================================================================== (a) Transfer of fossil operations to FirstEnergy Generation Company (FGCO). (b) Purchased power from power supply agreement (PSA). (c) Payroll taxes related to employees transferred to FGCO. (d) Transmission services received from ATSI. (e) Depreciation and property taxes related to transmission assets sold to ATSI. (f) Interest on note receivable from ATSI.
Results of Operations - --------------------- Earnings on common stock in 2002 decreased 96% to $2.0 million from $46.8 million in 2001 and $121.0 million in 2000. Excluding the effects shown in the table above, earnings on common stock increased by 4.1% in 2001 from 2000, being favorably affected by reduced operating expenses and taxes, and lower net interest charges, which were substantially offset by reduced operating revenues. Operating revenues decreased by $107.3 million or 9.8% in 2002, compared with 2001. The lower revenues reflect the effects of a sluggish national economy on our service area, shopping by Ohio customers for alternative energy providers and decreases in wholesale revenues. Retail kilowatt-hour sales declined by 11.4% in 2002 from the prior year, with declines in all customer sectors (residential, commercial and industrial), resulting in a $34.4 million reduction in generation sales revenue. Our lower generation kilowatt-hour sales resulted primarily from customer choice in Ohio. Sales of electric generation by alternative suppliers as a percent of total sales delivered in our franchise area increased to 17.0% in 2002 from 5.6% in 2001. Distribution deliveries increased 0.8% in 2002, compared with 2001, but revenues from electricity throughput decreased by $11.1 million in 2002 from the prior year due to lower unit prices. The higher distribution deliveries resulted from additional residential and commercial demand due to warmer summer weather that was more than offset by the effect that continued sluggishness in the economy had on demand by the industrial customers. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, further reduced operating revenues by $15.0 million in 2002 from the prior year. These revenue reductions are deferred for future recovery under our transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers decreased by $45.1 million in 2002 compared to 2001, due to lower kilowatt-hour sales and a decline in market prices. Reduced wholesale kilowatt-hour sales resulted principally from lower sales to FES reflecting the extended outage at Davis-Besse (see Davis-Besse Restoration). Excluding the effects shown in the table above, operating revenues decreased by $54.7 million or 5.7% in 2001 from 2000 following a $33.8 million increase in 2000 from the prior year. Customer choice in Ohio and the influence of a declining national economy on our regional business activity combined to lower operating revenues. Sales of electric generation provided by other suppliers in our service area represented 5.6% of total energy delivered in 2001. Retail generation sales declined in all customer categories resulting in an overall 4.0% reduction in kilowatt-hour sales from the prior year. Distribution deliveries increased 1.7% in 2001 from the prior year despite the weaker national economic environment. As part of Ohio's electric utility restructuring law, the implementation of a 5% reduction in generation charges for residential customers reduced operating revenues by approximately $8.0 million in 2001, compared to 2000. Operating revenues were also lower in 2001 from the prior year due to the absence of revenues associated with the low-income payment plan now administered by the Ohio Department of Development; there was also a corresponding reduction in other operating costs associated with that change. Revenues from kilowatt-hour sales to wholesale customers declined by $36.5 million in 2001 from 2000, with a corresponding 37.2% reduction in kilowatt-hour sales. Changes in KWH Sales 2002 2001 - ------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (11.4)% (4.0)% Wholesale............................. (27.6)% (37.2)% - ------------------------------------------------------------------- Total Electric Generation Sales......... (19.2)% (11.8)% =================================================================== Distribution Deliveries: Residential........................... 7.5% 3.4% Commercial and industrial............. (1.0)% 1.1% - ------------------------------------------------------------------- Total Distribution Deliveries........... 0.8% 1.7% =================================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $56.9 million in 2002 and increased by $227.9 million in 2001 from 2000. Excluding the effects of restructuring, total 2001 operating expenses and taxes were $48.0 million lower than the prior year. The following table presents changes from the prior year by expense category excluding the impact of restructuring. Operating Expenses and Taxes - Changes 2002 2001 - --------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel and purchased power...................... $(90.5) $(49.8) Nuclear operating costs....................... 96.8 (16.5) Other operating costs......................... 12.0 8.9 - --------------------------------------------------------------------- Total operation and maintenance expenses.... 18.3 (57.4) ===================================================================== Provision for depreciation and amortization... (36.7) 28.0 General taxes................................. (4.6) (27.7) Income taxes.................................. (33.9) 9.1 - --------------------------------------------------------------------- Total operating expenses and taxes.......... $(56.9) $(48.0) ===================================================================== Lower fuel and purchased power costs in 2002, compared to 2001, resulted from a $69.0 million reduction in purchased power from FES, reflecting lower kilowatt-hours purchased due to reduced kilowatt-hour sales and lower unit prices. Nuclear operating costs increased by $96.8 million in 2002, primarily due to approximately $55.9 million of incremental Davis-Besse maintenance costs related to the extended outage (see Davis-Besse Restoration). During 2002, costs also included amounts incurred for refueling outages at two nuclear plants (Beaver Valley Unit 2 and Davis-Besse), compared to only one outage (Perry) in 2001. The $12.0 million increase in other operating costs in 2002 resulted principally from higher employee benefit costs, employee severance costs and uncollectible accounts expense. The decrease in fuel and purchased power costs in 2001, compared to 2000, reflects the transfer of fossil operations to FGCO with our power requirements being provided under the PSA. There was one less nuclear refueling outage in 2001, compared to 2000, resulting in a $16.5 million decrease in nuclear operating costs from the prior year. Other operating costs increased by $8.9 million in 2001 from the prior year, reflecting planned maintenance work at the Bruce Mansfield Plant and the absence in 2001 of gains from the sale of emission allowances, offset in part by a reduction in low-income payment plan customer costs, decreased storm damage costs and the absence of costs incurred in 2000 related to the development of a distribution communications system. Charges for depreciation and amortization decreased by $36.7 million in 2002 from 2001. This decrease reflects higher shopping incentive deferrals and tax-related deferrals under TE's transition plan and the cessation of goodwill amortization beginning January 1, 2002, upon implementation of Statement of Financial Accounting Standards No. (SFAS) 142 "Goodwill and Other Intangible Assets." TE's goodwill amortization in 2001 totaled $ 12.4 million. Depreciation and amortization increased by $28.0 million in 2001 from the prior year due to incremental transition cost amortization under our transition plan, partially offset by new deferrals for shopping incentives. General taxes decreased by $4.6 million in 2002 from 2001 due to state tax changes in connection with the Ohio electric industry restructuring. Net Interest Charges Net interest charges continued to trend lower decreasing by $3.1 million in 2002 and $6.6 million in 2001, compared to the prior year. We continued to redeem and refinance outstanding debt and preferred stock during 2002 -- net redemptions and refinancing activities totaled $264.1 million and $51.8 million, respectively, and will result in annualized savings of $23.2 million. Capital Resources and Liquidity - ------------------------------- Through net debt and preferred stock redemptions, we continued to reduce the cost of debt and preferred stock, and improve our financial position in 2002. During 2002, we reduced total debt by approximately $163 million. Our common stockholder's equity as a percentage of capitalization increased to 51% as of December 31, 2002 from 27% at the end of 1997. Over the last five years, we have reduced the average cost of outstanding debt from 9.13% in 1997 to 6.61% in 2002. Changes in Cash Position As of December 31, 2002, we had $20.7 million of cash and cash equivalents, which was used to redeem long-term debt in January 2003, compared with $0.3 million as of December 31, 2001. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Our consolidated net cash from operating activities is provided by our regulated energy services. Net cash provided from operating activities was $156 million in 2002 and $190 million in 2001. Cash flows provided from 2002 and 2001 operating activities are as follows: Operating Cash Flows 2002 2001 ------------------------------------------------------------- (In millions) Cash earnings (1) $111 $223 Working capital and other 45 (33) ------------------------------------------------------------- Total $156 $190 ============================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Cash Flows From Financing Activities In 2002, the net cash used for financing activities of $29 million primarily reflects the redemptions of debt and preferred stock shown below. The following table provides details regarding new issues and redemptions during 2002: Securities Issued or Redeemed in 2002 --------------------------------------------------------------- (In millions) New Issues ---------- Pollution Control Notes $ 20 Redemptions ----------- Unsecured Notes 135 Secured Notes 44 Preferred Stock 85 Other, principally redemption premiums 2 --------------------------------------------------------------- 266 Short-term Borrowings, Net 132 --------------------------------------------------------------- In 2001, net cash used for financing activities totaled $97.8 million, primarily due to redemptions of $42 million of long-term debt notes and dividend payments of $30.8 million. We had about $22.6 million of cash and temporary investments and $149.7 million of short-term indebtedness as of December 31, 2002. Under our first mortgage indenture, as of December 31, 2002, we had the capability to issue $144 million of additional first mortgage bonds on the basis of property additions and retired bonds. Based on our earnings in 2002 under the earnings coverage test contained in our charter, we could not issue additional preferred stock (assuming no additional debt was issued). At the end of 2002, our common equity as a percentage of capitalization, stood at 51% compared to 45% at the end of 2001. The higher common equity percentage in 2002 compared to 2001 resulted from net redemptions of preferred stock and long-term debt and a $100 million equity contribution from FirstEnergy. Cash Flows From Investing Activities Net cash used in investing activities totaled $106 million in 2002. The net cash used for investing resulted from property additions. Expenditures for property additions primarily include expenditures supporting our distribution of electricity. In 2001, net cash used in investing activities totaled $93 million, principally due to property additions and the sale of property to affiliates as part of corporate separation and the sale to ATSI discussed above. Our cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, we expect to meet our contractual obligations with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets.
Less than 1-3 3-5 More than Contractual Obligations Total 1 Year Years Years 5 Years - ---------------------------------------------------------------------------------------------------------------- (In millions) Long-term debt................... $ 730 $116 $215 $ 30 $ 369 Short-term borrowings............ 150 150 -- -- -- Preferred stock (1).............. -- -- -- -- -- Capital leases (2)............... -- -- -- -- -- Operating leases (2)............. 1,067 75 153 158 681 Purchases (3).................... 269 30 75 64 100 - -------------------------------------------------------------------------------------------------------------- Total....................... $2,216 $371 $443 $252 $1,150 - -------------------------------------------------------------------------------------------------------------- (1) Subject to mandatory redemption. (2) Operating lease payments are net of capital trust receipts of $363.3 million (see Note 2). (3) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.
Our capital spending for the period 2003-2007 is expected to be about $169 million (excluding nuclear fuel) of which $54 million applies to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $34 million, of which about $12 million relates to 2003. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $40 million and $19 million, respectively, as the nuclear fuel is consumed. On February 22, 2002, Moody's Investor Service changed its credit rating outlook for FirstEnergy from stable to negative. The change was based upon a decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania Public Utility Commission (PPUC) for reconsideration its decision on the mechanism for sharing merger savings and reversed the PPUC's decisions regarding rate relief and accounting deferrals rendered in connection with its approval of the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed its outlook for FirstEnergy's credit ratings from stable to negative citing recent developments including: damage to the Davis-Besse reactor vessel head, the Pennsylvania Commonwealth Court decision, and deteriorating market conditions for some sales of FirstEnergy's remaining non-core assets. On July 31, 2002, Fitch revised its rating outlook for FirstEnergy to negative from stable. The revised outlook reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's judgment about NRG's financial ability to consummate the purchase of four power plants from FirstEnergy (see Note 6 - Sale of Generating Assets) and Fitch's expectation of subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while NRG's liquidity position added uncertainty to FirstEnergy's sale of power plants to NRG, its ratings would not be affected. S&P found FirstEnergy's cash flows sufficiently stable to support a continued (although delayed) program of debt and preferred stock redemption. S&P noted that it would continue to closely monitor FirstEnergy's progress on various initiatives. On January 21, 2003, S&P indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa (FirstEnergy's Argentina Operations), which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining its current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the Jersey Central Power & Light Company rate case, successful hedging of its short power position, and continued capture of projected merger savings. While FirstEnergy anticipates being prepared to restart the Davis-Besse plant in the spring of 2003 the Nuclear Regulatory Commission (NRC) must authorize the unit's restart following a formal inspection process prior to its returning the unit to service. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt could put additional pressure on the Company's credit ratings. Other Obligations Obligations not included on our Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2, which are reflected in the operating lease payments above (see Note 2 - Leases). The present value as of December 31, 2002, of these sale and leaseback operating lease commitments, net of trust investments, total $621 million. We sell substantially all of our retail customer receivables, which provided $52 million of off balance sheet financing as of December 31, 2002. Interest Rate Risk - ------------------ Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the table below. We are subject to the inherent risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 2, our investment in the Shippingport Capital Trust effectively reduces future lease obligations, also reducing interest rate risk. Changes in the market value of our nuclear decommissioning trust funds had been recognized by making corresponding changes to the decommissioning liability, as described in Note 1 - Utility Plant and Depreciation. In conjunction with the adoption of SFAS 143, "Accounting for Asset Retirement Obligations," on January 1, 2003, we reclassified unrealized gains and losses to Other Comprehensive Income (OCI) in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity." While fluctuations in the fair value of our Ohio EUOCs' trust balances will eventually affect earnings (affecting OCI initially) based on the guidance provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from customers the difference between the investments held in trust and their decommissioning obligations. Thus, in absence of disallowed costs, there should be no earnings effect from fluctuations in their decommissioning trust balances. As of December 31, 2002, decommissioning trust balances totaled $1.050 billion, with $698 million held by our Ohio EUOC and the balance held by our non-Ohio EUOC. As of year end 2002, trust balances included 51% of equity and 49% of debt instruments. The table below presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value - ------------------------------------------------------------------------------------------------------------------- There- Fair 2003 2004 2005 2006 2007 after Total Value - -------------------------------------------------------------------------------------------------------------------- (Dollars in millions) Assets - -------------------------------------------------------------------------------------------------------------------- Investments other than Cash and Cash Equivalents: Fixed Income................. $ 20 $ 9 $134 $12 $ 9 $290 $474 $515 Average interest rate..... 7.7% 7.7% 7.8% 7.7% 7.7% 6.8% 7.2% - -------------------------------------------------------------------------------------------------------------------- Liabilities - -------------------------------------------------------------------------------------------------------------------- Long-term Debt: Fixed rate................... $116 $215 $30 $160 $521 $562 Average interest rate .... 7.7% 7.8% 7.1% 7.8% 7.7% Variable rate................ $209 $209 $210 Average interest rate..... 3.0% 3.0% Short-term Borrowings........ $150 $150 $150 Average interest rate..... 1.8% 1.8% - --------------------------------------------------------------------------------------------------------------------
Equity Price Risk - ----------------- Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $90 million and $90 million as of December 31, 2002 and 2001, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $9 million reduction in fair value as of December 31, 2002 (see Note 1K - Supplemental Cash Flows Information) Outlook - ------- Our industry continues to transition to a more competitive environment. In 2001, all our customers could select alternative energy suppliers. We continue to deliver power to residential homes and businesses through our existing distribution systems, which remain regulated. Customer rates have been restructured into separate components to support customer choice. We have a continuing responsibility to provide power to our customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters Beginning on January 1, 2001, Ohio customers were able to choose their electricity suppliers. Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of our customers elects to obtain power from an alternative supplier, we reduce the customer's bill with a "generation shopping credit," based on the regulated generation component plus an incentive, and the customer receives a generation charge from the alternative supplier. We have continuing responsibility to provide energy to our franchise customers as the PLR through December 31, 2005. Regulatory assets are costs which have been authorized by the Public Utilities Commission of Ohio (PUCO) for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of our regulatory assets are expected to continue to be recovered under the provisions of our transition plan as discussed below. Our regulatory assets are $392.6 million as of December 31, 2002 and $388.8 million as of December 31, 2001. The transition cost portion of rates provides for recovery of certain amounts not otherwise recoverable in a competitive generation market (such as regulatory assets). Transition costs are paid by all customers whether or not they choose an alternative supplier. Under the PUCO-approved transition plan, we assumed the risk of not recovering up to $80 million of transition revenue if the rate of customers (excluding contracts and full-service accounts) switching from our service to an alternative supplier did not reach 20% for any consecutive twelve-month period by December 31, 2005 - the end of the market development period. That goal was achieved in 2002. Accordingly, TE does not believe that there will be any regulatory action reducing the recoverable transition costs. As part of our Ohio transition plan we are obligated to supply electricity to customers who do not choose an alternative supplier. We are also required to provided 160 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within our service area. Our competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of our load. In 2003, the total peak load forecasted for customers electing to stay with us, including the 160 MW of low cost supply and the load served by our affiliate is 2,020 MW. Davis-Besse Restoration On April 30, 2002, the NRC initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FirstEnergy Nuclear Operating Company (FENOC), an affiliated company, in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, we have made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FENOC is also accelerating maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, FENOC discussed plans to test the bottom of the reactor for leaks and to install a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FENOC anticipates that the unit will be ready for restart in the spring of 2003 after completion of the additional maintenance work and regulatory reviews. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed our plans to reduce post-merger debt levels we believe such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval could trigger an evaluation for impairment of our investment in the plant (see Significant Accounting Policies below). The actual costs (capital and expense) associated with the extended Davis-Besse outage (TE share - 48.62%) in 2002 and estimated costs in 2003 are: Costs of Davis-Besse Extended Outage 100% ------------------------------------------------------------------------- (In millions) 2002 - Actual ------------- Capital Expenditures: Reactor head and restart ................................ $ 63.3 Incremental Expenses (pre-tax): Maintenance ............................................. 115.0 Fuel and purchased power ................................ 119.5 ------------------------------------------------------------------------- Total ................................................... $234.5 ========================================================================= 2003 - Estimated ---------------- Primarily operating expenses (pre-tax): Maintenance (including acceleration of programs) ........ $50 Replacement power per month ............................. $12-18 ------------------------------------------------------------------------- Environmental Matters We believe we are in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 5 - Environmental Matters). We continue to evaluate our compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. We have been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved, are often unsubstantiated and subject to dispute. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. We have accrued a liability of $0.2 million as of December 31, 2002, based on estimates of the total costs of cleanup, the proportionate responsibility of other PRPs for such costs and the financial ability of other PRPs to pay. We believe that waste disposal costs will not have a material adverse effect on our financial condition, cash flows, or results of operations. The effects of compliance on the Company with regard to environmental matters could have a material adverse effect on our earnings and competitive position. These environmental regulations affect our earnings and competitive position to the extent we compete with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. We believe we are in material compliance with existing regulations, but are unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Significant Accounting Policies - ------------------------------- We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect our financial results. All of our assets are subject to their own specific risks and uncertainties and are continually reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Our more significant accounting policies are described below. Regulatory Accounting We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on our costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio, significant amounts of regulatory assets have been recorded -- $392.6 million as of December 31, 2002. We continually review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hour that have been delivered but not yet been billed through the end of the year. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligation. Due to the significant decline in corporate bond yields and interest rates in general during 2002, we reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000. Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. The market values of our pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002, 2001 and 2000, plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, we will not be required to fund our pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to our 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. The effect on our SFAS 87 and 106 costs and liabilities from changes in key assumptions are as follows:
Increase in Costs from Adverse Changes in Key Assumptions ------------------------------------------------------------------------------------------------ Assumption Adverse Change Pension OPEB Total ------------------------------------------------------------------------------------------------ (In millions) Discount rate Decrease by 0.25% $0.2 $0.2 $0.4 Long-term return on assets Decrease by 0.25% 0.1 -- 0.1 Health care trend rate Increase by 1% na 0.5 0.5 Increase in Minimum Pension Liability ------------------------------------- Discount rate Decrease by 0.25% 4.4 na 4.4 ------------------------------------------------------------------------------------------------
As a result of the reduced market value of our pension plan assets, we were required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. We eliminated our prepaid pension asset of $18.7 million and established a minimum liability of $25.0 million, recording an intangible asset of $7.6 million and reducing OCI by $21.1 million (recording a related deferred tax benefit of $15.0 million). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002 increased due to the lower discount rate assumed and reduced market value of plan assets as of December 31, 2002. Our non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $3 million and $1 million, respectively - a total of $4 million in 2003 as compared to 2002. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset, is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur we would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill. The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. As of December 31, 2002, we had approximately $445.7 million of goodwill. Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- SFAS 143, "Accounting for Asset Retirement Obligations" In June 2001, the FASB issued SFAS 143. The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize regulatory assets or liabilities if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. We have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $123.2 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $15.0 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144. No impairment was indicated. The asset retirement liability at the date of adoption was $172 million. As of December 31, 2002, the Company had recorded decommissioning liabilities of $180.9 million, including unrealized gains on decommissioning trust funds of $1.9 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. The cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a 115.2 million increase to income ($67.3 million net of tax). The $1.9 million of unrealized gains ($1.1 million net of tax) included in the decommissioning liability balances as of December 31, 2002, were offset against OCI upon adoption of SFAS 143. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities" This statement, which was issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time they are incurred rather than when management commits to a plan of exit or disposal. It also requires the use of fair value for the measurement of such liabilities. The new standard supersedes guidance provided by EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This new standard was effective for exit and disposal activities initiated after December 31, 2002. Since it is applied prospectively, there will be no impact upon adoption. However, SFAS 146 could change the timing and amount of costs recognized in connection with future exit or disposal activities. FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002 (see Guarantees and Other Assurances). It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. We currently have transactions with entities which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. We currently consolidate the majority of these entities and believe we will continue to consolidate following the adoption of FIN 46. One of these entities we are currently consolidating is the Shippingport Capital Trust which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of our interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated parties and 0.34 percent equity interest by Toledo Edison Capital Corp., a majority owned subsidiary.
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------ (In thousands) OPERATING REVENUES (a) (Note 1).................................. $987,645 $1,094,903 $954,947 -------- ---------- -------- OPERATING EXPENSES AND TAXES: Fuel and purchased power (Note 1)............................. 366,932 457,444 159,039 Nuclear operating costs (Note 1).............................. 258,308 161,532 178,063 Other operating costs (Note 1)................................ 163,267 151,244 156,286 -------- ---------- -------- Total operation and maintenance expenses.................... 788,507 770,220 493,388 Provision for depreciation and amortization................... 93,482 130,196 104,914 General taxes................................................. 53,223 57,810 90,837 Income taxes.................................................. (2,745) 31,193 72,394 -------- ---------- -------- Total operating expenses and taxes.......................... 932,467 989,419 761,533 -------- ---------- -------- OPERATING INCOME................................................. 55,178 105,484 193,414 OTHER INCOME (Note 1)............................................ 13,329 15,652 8,669 -------- ---------- -------- INCOME BEFORE NET INTEREST CHARGES............................... 68,507 121,136 202,083 -------- ---------- -------- NET INTEREST CHARGES: Interest on long-term debt.................................... 58,120 66,463 72,892 Allowance for borrowed funds used during construction................................................ (2,502) (3,848) (6,523) Other interest expense (credit)............................... (448) (4,390) (1,519) -------- ---------- -------- Net interest charges........................................ 55,170 58,225 64,850 -------- ---------- -------- NET INCOME....................................................... 13,337 62,911 137,233 PREFERRED STOCK DIVIDEND REQUIREMENTS.................................................. 11,356 16,135 16,247 -------- ---------- -------- EARNINGS ON COMMON STOCK......................................... $ 1,981 $ 46,776 $120,986 ======== ========== ======== (a) Includes electric sales to associated companies of $232.2 million, $277.9 million and $142.3 million in 2002, 2001 and 2000, respectively. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------- (In thousands) ASSETS UTILITY PLANT: In service................................................................... $1,600,860 $1,578,943 Less-Accumulated provision for depreciation.................................. 706,772 645,865 ---------- ---------- 894,088 933,078 ---------- ---------- Construction work in progress- Electric plant............................................................. 104,091 40,220 Nuclear fuel............................................................... 33,650 19,854 ---------- ---------- 137,741 60,074 ---------- ---------- 1,031,829 993,152 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust (Note 2).......................................... 240,963 262,131 Nuclear plant decommissioning trusts......................................... 174,514 156,084 Long-term notes receivable from associated companies......................... 162,159 162,347 Other........................................................................ 2,236 4,248 ---------- ---------- 579,872 584,810 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents.................................................... 20,688 302 Receivables- Customers.................................................................. 4,711 5,922 Associated companies....................................................... 55,245 64,667 Other...................................................................... 6,778 9,709 Notes receivable from associated companies................................... 1,957 7,607 Materials and supplies, at average cost- Owned...................................................................... 13,631 13,996 Under consignment.......................................................... 22,997 17,050 Prepayments and other........................................................ 3,455 14,580 ---------- ---------- 129,462 133,833 ---------- ---------- DEFERRED CHARGES: Regulatory assets............................................................ 392,643 388,846 Goodwill..................................................................... 445,732 445,732 Property taxes............................................................... 23,429 23,836 Other........................................................................ 14,257 1,909 ---------- ---------- 876,061 860,323 ---------- ---------- $2,617,224 $2,572,118 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity.................................................. $ 712,931 $ 637,665 Preferred stock not subject to mandatory redemption.......................... 126,000 126,000 Long-term debt............................................................... 557,265 646,174 ---------- ---------- 1,396,196 1,409,839 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock......................... 189,355 347,593 Accounts payable- Associated companies....................................................... 171,862 53,960 Other...................................................................... 8,638 27,418 Notes payable to associated companies........................................ 149,653 17,208 Accrued taxes............................................................... 34,967 39,848 Accrued interest............................................................. 16,377 19,918 Other........................................................................ 57,232 40,222 ---------- ---------- 628,084 546,167 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes............................................ 223,087 213,145 Accumulated deferred investment tax credits.................................. 29,491 31,342 Nuclear plant decommissioning costs.......................................... 180,856 162,426 Pensions and other postretirement benefits................................... 82,553 120,561 Other........................................................................ 76,957 88,638 ---------- ---------- 592,944 616,112 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 2 and 5).............................................................. ---------- ---------- $2,617,224 $2,572,118 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, $5 par value, authorized 60,000,000 shares 39,133,887 shares outstanding.................................................. $ 195,670 $ 195,670 Other paid-in capital............................................................ 428,559 328,559 Accumulated other comprehensive loss (Note 3E)................................... (21,115) -- Retained earnings (Note 3A)...................................................... 109,817 113,436 ---------- ---------- Total common stockholder's equity.............................................. 712,931 637,665 ---------- ---------- Number of Shares Optional Outstanding Redemption Price ------------------- ------------------------ 2002 2001 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK (Note 3C): Cumulative, $100 par value- Authorized 3,000,000 shares Not Subject to Mandatory Redemption: $ 4.25............................ 160,000 160,000 $104.63 $ 16,740 16,000 16,000 $ 4.56............................ 50,000 50,000 101.00 5,050 5,000 5,000 $ 4.25............................ 100,000 100,000 102.00 10,200 10,000 10,000 $ 8.32............................ -- 100,000 -- -- -- 10,000 $ 7.76............................ -- 150,000 -- -- -- 15,000 $ 7.80............................ -- 150,000 -- -- -- 15,000 $10.00............................ -- 190,000 -- -- -- 19,000 --------- --------- -------- ---------- ---------- 310,000 900,000 31,990 31,000 90,000 Redemption Within One Year -- (59,000) --------- --------- -------- ---------- ---------- 310,000 900,000 31,990 31,000 31,000 --------- --------- -------- ---------- ---------- Cumulative, $25 par value- Authorized 12,000,000 shares Not Subject to Mandatory Redemption: $2.21............................. -- 1,000,000 -- -- -- 25,000 $2.365............................ 1,400,000 1,400,000 27.75 38,850 35,000 35,000 Adjustable Series A............... 1,200,000 1,200,000 25.00 30,000 30,000 30,000 Adjustable Series B............... 1,200,000 1,200,000 25.00 30,000 30,000 30,000 --------- --------- -------- ---------- ---------- 3,800,000 4,800,000 98,850 95,000 120,000 Redemption Within One Year.......... -- (25,000) --------- --------- -------- ---------- ---------- 3,800,000 4,800,000 98,850 95,000 95,000 --------- --------- -------- ---------- ---------- Total Not Subject to Mandatory Redemption.................... 4,110,000 5,700,000 $130,840 126,000 126,000 ========= ========= ======== ---------- ---------- LONG-TERM DEBT (Note 3D): First mortgage bonds: 8.000% due 2003................................................................ 33,725 34,125 7.875% due 2004................................................................ 145,000 145,000 ---------- ---------- Total first mortgage bonds..................................................... 178,725 179,125 ---------- ---------- Unsecured notes and debentures: 8.700% due 2002................................................................ -- 135,000 10.000% due 2003-2010........................................................... 910 940 * 4.850% due 2030................................................................ 34,850 34,850 * 4.000% due 2033................................................................ 5,700 5,700 * 4.500% due 2033................................................................ 31,600 31,600 * 5.580% due 2033................................................................ 18,800 18,800 ---------- ---------- Total unsecured notes and debentures........................................... 91,860 226,890 ---------- ----------
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd) As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------- (In thousands) LONG-TERM DEBT (Cont'd): Secured notes: 8.180% due 2002.................................................................. -- 17,000 8.620% due 2002.................................................................. -- 7,000 8.650% due 2002.................................................................. -- 5,000 7.760% due 2003.................................................................. 5,000 5,000 7.780% due 2003.................................................................. 1,000 1,000 7.820% due 2003.................................................................. 38,400 38,400 7.850% due 2003.................................................................. 15,000 15,000 7.910% due 2003.................................................................. 3,000 3,000 7.670% due 2004.................................................................. 70,000 70,000 7.130% due 2007.................................................................. 30,000 30,000 7.625% due 2020.................................................................. 45,000 45,000 7.750% due 2020.................................................................. 54,000 54,000 9.220% due 2021.................................................................. 15,000 15,000 10.000% due 2021.................................................................. -- 15,000 6.875% due 2023.................................................................. 20,200 20,200 8.000% due 2023.................................................................. 30,500 30,500 *1.700% due 2024.................................................................. 67,300 67,300 6.100% due 2027.................................................................. 10,100 10,100 5.375% due 2028.................................................................. 3,751 3,751 *1.400% due 2033.................................................................. 30,900 30,900 *1.350% due 2033.................................................................. 20,200 -- ---------- ---------- Total secured notes............................................................ 459,351 483,151 ---------- ---------- Capital lease obligations (Note 2).................................................... -- 263 ---------- ---------- Net unamortized premium on debt....................................................... 16,684 20,338 ---------- ---------- Long-term debt due within one year.................................................... (189,355) (263,593) ---------- ---------- Total long-term debt........................................................... 557,265 646,174 ---------- ---------- TOTAL CAPITALIZATION.................................................................. $1,396,196 $1,409,839 ========== ========== * Denotes variable rate issue with December 31, 2002 interest rate shown. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Accumulated Other Other Comprehensive Number Par Paid-In Comprehensive Retained Income (Loss) of Shares Value Capital Income (Loss) Earnings ------------- --------- ----- ------- ------------- -------- (Dollars in thousands) Balance, January 1, 2000............... 39,133,887 $195,670 $328,559 $ -- $ 27,475 Net income.......................... $137,233 137,233 ======== Cash dividends on preferred stock... (16,250) Cash dividends on common stock...... (67,100) - --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000............. 39,133,887 195,670 328,559 -- 81,358 Net income.......................... $ 62,911 62,911 ======== Cash dividends on preferred stock... (16,133) Cash dividends on common stock...... (14,700) - --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001............. 39,133,887 195,670 328,559 -- 113,436 Net income.......................... $ 13,337 13,337 Minimum liability for unfunded retirement benefits, net of $(15,042,000) of income taxes..... (21,115) (21,115) -------- Comprehensive loss.................. $ (7,778) ======== Equity contribution from parent..... 100,000 Cash dividends on preferred stock... (10,057) Cash dividends on common stock...... (5,600) Preferred stock redemption premiums. (1,299) - --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002............. 39,133,887 $195,670 $428,559 $(21,115) $109,817 =====================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Mandatory Redemption -------------------- of Shares Value --------- ----- (Dollars in thousands) Balance, January 1, 2000..... 5,700,000 $210,000 ---------------------------------------------------- Balance, December 31, 2000... 5,700,000 210,000 ---------------------------------------------------- Balance, December 31, 2001... 5,700,000 210,000 ---------------------------------------------------- Redemptions $8.32 Series............. (100,000) (10,000) $7.76 Series............. (150,000) (15,000) $7.80 Series............. (150,000) (15,000) $10.00 Series ............ (190,000) (19,000) $2.21 Series............. (1,000,000) (25,000) ---------------------------------------------------- Balance, December 31, 2002... 4,110,000 $126,000 ==================================================== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income......................................................... $ 13,337 $ 62,911 $ 137,233 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization................... 93,482 130,196 104,914 Nuclear fuel and lease amortization........................... 11,866 22,222 23,881 Deferred income taxes, net.................................... (5,868) 11,897 20,376 Investment tax credits, net................................... (1,851) (3,832) (1,827) Receivables................................................... 13,564 (9,837) (6,671) Materials and supplies........................................ (5,582) 8,336 4,093 Accounts payable.............................................. 42,501 19,744 13,997 Other (Note 7)................................................ (5,911) (51,781) (38,180) --------- --------- --------- Net cash provided from operating activities................. 155,538 189,856 257,816 --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt................................................ 19,580 -- 96,405 Short-term borrowings, net.................................... 132,445 -- 8,060 Equity contributions from parent.............................. 100,000 -- -- Redemptions and Repayments- Preferred stock............................................... (85,299) -- -- Long-term debt................................................ (180,368) (42,265) (200,633) Short-term borrowings, net.................................... -- (24,728) -- Dividend Payments- Common stock.................................................. (5,600) (14,700) (67,100) Preferred stock............................................... (10,057) (16,135) (16,247) --------- --------- --------- Net cash provided from (used for) financing activities...... (29,299) (97,828) (179,515) --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions................................................. (105,510) (112,451) (92,860) Loans to associated companies...................................... -- (123,438) (63,838) Loan payments from associated companies............................ 5,838 25,185 -- Capital trust investments.......................................... 21,168 17,705 15,618 Sale of assets to associated companies............................. -- 123,438 81,014 Other ............................................................. (27,349) (23,550) (17,162) --------- --------- --------- Net cash provided from (used for) investing activities...... (105,853) (93,111) (77,228) --------- --------- --------- Net increase (decrease) in cash and cash equivalents............... 20,386 (1,083) 1,073 Cash and cash equivalents at beginning of year..................... 302 1,385 312 --------- --------- --------- Cash and cash equivalents at end of year........................... $ 20,688 $ 302 $ 1,385 ========= ========= ========= SUPPLEMENTAL CASH FLOWS INFORMATION: Cash Paid During the Year- Interest (net of amounts capitalized)........................... $ 61,498 $ 63,159 $ 71,009 ========= ========= ========= Income taxes.................................................... $ 3,561 $ 33,210 $ 65,553 ========= ========= ========= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF TAXES For the Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------ (In thousands) GENERAL TAXES: Real and personal property......................................... $ 22,737 $ 23,624 $ 46,302 Ohio kilowatt-hour excise*......................................... 28,046 19,576 -- State gross receipts*.............................................. -- 12,789 36,813 Social security and unemployment................................... 1,684 1,128 7,220 Other.............................................................. 756 693 502 -------- -------- -------- Total general taxes......................................... $ 53,223 $ 57,810 $ 90,837 ======== ======== ======== PROVISION FOR INCOME TAXES: Currently payable- Federal......................................................... $ 9,669 $ 25,640 $ 56,631 State........................................................... 2,957 5,937 1,811 -------- -------- -------- 12,626 31,577 58,442 -------- -------- -------- Deferred, net- Federal......................................................... (5,312) 11,736 20,865 State........................................................... (556) 161 (489) -------- -------- -------- (5,868) 11,897 20,376 -------- -------- -------- Investment tax credit amortization................................. (1,851) (3,832) (1,827) -------- -------- -------- Total provision for income taxes............................ $ 4,907 $ 39,642 $ 76,991 ======== ======== ======== INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating income................................................... $ (2,745) $ 31,193 $ 72,394 Other income....................................................... 7,652 8,449 4,597 -------- -------- -------- Total provision for income taxes............................ $ 4,907 $ 39,642 $ 76,991 ======== ======== ======== RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes...................... $ 18,244 $102,553 $214,224 ======== ======== ======== Federal income tax expense at statutory rate....................... $ 6,385 $ 35,894 $ 74,978 Increases (reductions) in taxes resulting from- State income taxes, net of federal income tax benefit........... 1,561 3,964 859 Amortization of investment tax credits.......................... (1,851) (3,832) (1,827) Amortization of tax regulatory assets........................... (1,969) (2,367) (1,737) Amortization of goodwill........................................ -- 4,351 4,334 Other, net...................................................... 781 1,632 384 -------- -------- -------- Total provision for income taxes............................ $ 4,907 $ 39,642 $ 76,991 ======== ======== ======== ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences......................................... $177,262 $171,976 $163,537 Competitive transition charge...................................... 121,392 135,462 70,264 Unamortized investment tax credits................................. (11,414) (12,184) (16,689) Unused alternative minimum tax credits............................. -- -- (5,100) Deferred gain for asset sale to affiliated company................. 14,186 16,305 15,330 Other comprehensive income......................................... (15,042) -- -- Other (Note 7)..................................................... (63,297) (98,414) (30,398) -------- -------- -------- Net deferred income tax liability............................... $223,087 $213,145 $196,944 ======== ======== ======== * Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include The Toledo Edison Company (Company) and its 90% owned subsidiary, The Toledo Edison Capital Corporation (TECC). The subsidiary was formed in 1997 to make equity investments in a business trust in connection with the financing transactions related to the Bruce Mansfield Plant sale and leaseback (see Note 2). The Cleveland Electric Illuminating Company (CEI), an affiliate, has a 10% interest in TECC. All significant intercompany transactions have been eliminated. The Company is a wholly owned subsidiary of FirstEnergy Corp. FirstEnergy holds directly all of the issued and outstanding common shares of its principal electric utility operating subsidiaries, including, the Company, CEI, Ohio Edison Company (OE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). JCP&L, Met-Ed and Penelec were formerly wholly owned subsidiaries of GPU, Inc. which merged with FirstEnergy on November 7, 2001. The Company follows the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. (A) CONSOLIDATION- The Company consolidates all majority-owned subsidiaries, after eliminating the effects of intercompany transactions. Non-majority owned investments, including investments in limited liability companies, partnerships and joint ventures, are accounted for under the equity method when the Company is able to influence their financial or operating policies. Investments in corporations resulting in voting control of 20% or more are presumed to be equity method investments. Limited partnerships are evaluated in accordance with SEC Staff D-46, "Accounting for Limited Partnership Investments" and American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence. For all remaining investments (excluding those within the scope of SFAS 115, the Company applies the cost method. (B) REVENUES- The Company's principal business is providing electric service to customers in northwestern Ohio. The Company's retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service through the end of the year. Receivables from customers include sales to residential, commercial and industrial customers located in the Company's service area and sales to wholesale customers. There was no material concentration of receivables at December 31, 2002 or 2001, with respect to any particular segment of the Company's customers. The Company and CEI sell substantially all of their retail customers' receivables to Centerior Funding Corporation (CFC), a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a SFAS 140 "qualified special purpose entity") under an asset-backed securitization agreement. Transfers are made in return for an interest in the trust (41% as of December 31, 2002), which is stated at fair value, reflecting adjustments for anticipated credit losses. The average collection period for billed receivables is 28 days. Given the short collection period after billing, the fair value of CFC's interest in the trust approximates the stated value of its retained interest in underlying receivables after adjusting for anticipated credit losses. Accordingly, subsequent measurements of the retained interest under SFAS 115 (as an available-for-sale financial instrument) result in no material change in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated credit losses would not have significantly affected the Company's retained interest in the pool of receivables through the trust. Of the $272 million sold to the trust and outstanding as of December 31, 2002, FirstEnergy had a retained interest in $111 million of the receivables included as other receivables on the Consolidated Balance Sheets. Accordingly, receivables recorded on the Consolidated Balance Sheets were reduced by approximately $161 million due to these sales. Collections of receivables previously transferred to the trust and used for the purchase of new receivables from CFC during 2002, totaled approximately $2.2 billion. The Company processed receivables for the trust and received servicing fees of approximately $1.3 million in 2002. Expenses associated with the factoring discount related to the sale of receivables were $4.7 million in 2002. (C) REGULATORY PLAN- In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. In July 2000, the PUCO approved FirstEnergy's transition plan for the Company, OE and CEI as modified by a settlement agreement with major parties to the transition plan. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation" to the Company's nonnuclear generation business was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $0.8 billion net of deferred income taxes and transition costs related to regulatory assets as filed of $0.5 billion net of deferred income taxes, with recovery through no later than mid-2007 for the Company, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $0.3 billion of impaired generating assets recognized as regulatory assets as described further below, $1.0 billion, net of deferred income taxes, of above market operating lease costs and $0.3 billion, net of deferred income taxes, of additional plant costs that were reflected on the Company's regulatory financial statements. Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 160 megawatts (MW) of generation capacity through 2005 at established prices for sales to the Company's retail customers. Customer prices are frozen through the five-year market development period except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Company was authorized increases in annual revenues aggregating approximately $5 million to recover its higher tax costs resulting from the Ohio deregulation legislation. The Company's customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be accomplished by extending the 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 period could have been shortened for the Company to reduce recovery by as much as $80 million. The Company has achieved its required 20% customer shopping goals in 2002. Accordingly, the Company believes that there will be no regulatory action reducing the recoverable transition costs. The application of SFAS 71 has been discontinued with respect to the Company's generation operations. The SEC issued interpretive guidance regarding asset impairment measurement that concluded any supplemental regulated cash flows such as a competitive transition charge should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance $53 million of impaired plant investments were recognized by the Company as regulatory assets recoverable as transition costs through future regulatory cash flows. Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued, were $559 million as of December 31, 2002. (D) UTILITY PLANT AND DEPRECIATION- Utility plant reflects the original cost of construction (except for the Company's nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 3.9% in 2002, 3.5% in 2001 and 3.4% in 2000. Annual depreciation expense includes approximately $28.5 million for future decommissioning costs applicable to the Company's ownership interests in three nuclear generating units (Beaver Valley Unit 2, Davis-Besse Unit 1 and Perry Unit 1). The Company's share of the future obligation to decommission these units is approximately $475 million in current dollars and (using a 4.0% escalation rate) approximately $1.0 billion in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Payments for decommissioning are expected to begin in 2016, when actual decommissioning work begins. The Company has recovered approximately $192 million for decommissioning through its electric rates from customers through December 31, 2002. The Company has also recognized an estimated liability of approximately $4.8 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy, as required by the Energy Policy Act of 1992. In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. The Company has identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143, asset retirement costs of $123 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $15 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets". No impairment was indicated. The asset retirement liability at the date of adoption will be $172 million. As of December 31, 2002, the Company had recorded decommissioning liabilities of $181 million, including unrealized gains on decommissioning trust funds of $2 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. The cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $115 million increase to income ($67 million net of tax). The $2 million of unrealized gains ($1 million net of tax) included in the decommissioning liability balances as of December 31, 2002 was offset against as other comprehensive income (OCI) upon adoption of SFAS 143. The FASB approved SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. Under SFAS 142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill is tested for impairment at least on an annual basis - based on the results of the transition analysis and the 2002 annual analysis, no impairment of the Company's goodwill is required. As described above under "Regulatory Plan" the Company recovers transition costs that represent a significant source of cash. The Company is unable to predict how completion of transition cost recovery will affect future goodwill impairment analyses. Prior to the adoption of SFAS 142, the Company amortized about $12.4 million of goodwill annually. The goodwill balance as of December 31, 2002 and 2001 was $446 million. The following table shows what net income would have been if goodwill amortization had been excluded from prior periods: 2002 2001 2000 ---- ---- ---- (In thousands) Reported net income................... $13,337 $62,911 $137,233 Add back goodwill amortization........ -- 12,432 12,384 ------- ------- -------- Adjusted net income................... $13,337 $75,343 $149,617 ======= ======= ======== (E) COMMON OWNERSHIP OF GENERATING FACILITIES- The Company, together with CEI and OE and its wholly owned subsidiary, Pennsylvania Power Company (Penn), own and/or lease, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly owned facility in the same proportion as its interest. The Company's portion of operating expenses associated with jointly owned facilities is included in the corresponding operating expenses on the Consolidated Statements of Income. The amounts reflected on the Consolidated Balance Sheet under utility plant at December 31, 2002 include the following:
Utility Accumulated Construction Ownership/ Plant Provision for Work in Leasehold Generating Units in Service Depreciation Progress Interest - ---------------------------------------------------------------------------------------------------- (In millions) Bruce Mansfield Units 2 and 3............... $ 46.0 $ 16.9 $21.0 18.61% Beaver Valley Unit 2.......... 3.2 0.2 8.8 19.91% Davis-Besse................... 222.6 48.9 54.4 48.62% Perry......................... 338.7 59.9 3.6 19.91% --------------------------------------------------------------------------------------------------- Total....................... $610.5 $125.9 $87.8 ====================================================================================================
The Bruce Mansfield Plant and Beaver Valley Unit 2 are being leased through sale and leaseback transactions (see Note 2) and the above-related amounts represent construction expenditures subsequent to the transaction. (F) NUCLEAR FUEL- Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Company amortizes the cost of nuclear fuel based on the rate of consumption. (G) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 3B). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date, resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows: 2002 2001 2000 - ---------------------------------------------------------------------------- Valuation assumptions: Expected option term (years)... 8.1 8.3 7.6 Expected volatility............ 23.31% 23.45% 21.77% Expected dividend yield........ 4.36% 5.00% 6.68% Risk-free interest rate........ 4.60% 4.67% 5.28% Fair value per option............ $6.45 $4.97 $2.86 --------------------------------------------------------------------------- The effects of applying fair value accounting to FirstEnergy's stock options would not materially effect the Company's net income. (H) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. The Company is included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Company recognizing any tax losses or credits it contributed to the consolidated return. (I) RETIREMENT BENEFITS- FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all of the Company's full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. On December 31, 2001, the GPU pension plans were merged with the FirstEnergy plan. The Company uses the projected unit credit method for funding purposes and was not required to make pension contributions during the three years ended December 31, 2002. The assets of the FirstEnergy pension plan consist primarily of common stocks, United States government bonds and corporate bonds. The Company provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company pays insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Company. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. As a result of the reduced market value of FirstEnergy's pension plan assets, it was required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. FirstEnergy's accumulated benefit obligation of $3.438 billion exceeded the fair value of plan assets ($2,889 billion) resulting in a minimum pension liability of $548.6 million. FirstEnergy eliminated its prepaid pension asset of $286.9 million (Company - -$18.7 million) and established a minimum liability of $548.6 million (Company - $25.0 million), recording an intangible asset of $78.5 million (Company - $7.6 million) and reducing OCI by $444.2 million (Company - $21.1 million) (recording a related deferred tax asset of $312.8 million (Company - $15.0 million)). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002, increased due to the lower discount rate and asset returns assumed as of December 31, 2002. The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Other Pension Benefits Postretirement Benefits ---------------- ----------------------- 2002 2001 2002 2001 ---------------------------------------------------------------------------------------------- (In millions) Change in benefit obligation: Benefit obligation as of January 1 ....... $3,547.9 $1,506.1 $1,581.6 $ 752.0 Service cost ............................. 58.8 34.9 28.5 18.3 Interest cost ............................ 249.3 133.3 113.6 64.4 Plan amendments .......................... -- 3.6 (121.1) -- Actuarial loss ........................... 268.0 123.1 440.4 73.3 Voluntary early retirement program ....... -- -- -- 2.3 GPU acquisition .......................... (11.8) 1,878.3 110.0 716.9 Benefits paid ............................ (245.8) (131.4) (83.0) (45.6) ------------------------------------------------------------------------------------------- Benefit obligation as of December 31 ..... 3,866.4 3,547.9 2,070.0 1,581.6 ------------------------------------------------------------------------------------------- Change in fair value of plan assets: Fair value of plan assets as of January 1 ............................... 3,483.7 1,706.0 535.0 23.0 Actual return on plan assets ............. (348.9) 8.1 (57.1) 12.7 Company contribution ..................... -- -- 37.9 43.3 GPU acquisition .......................... -- 1,901.0 -- 462.0 Benefits paid ............................ (245.8) (131.4) (42.5) (6.0) ------------------------------------------------------------------------------------------- Fair value of plan assets as of December 31 ............................. 2,889.0 3,483.7 473.3 535.0 ------------------------------------------------------------------------------------------- Funded status of plan .................... (977.4) (64.2) (1,596.7) (1,046.6) Unrecognized actuarial loss .............. 1,185.8 222.8 751.6 212.8 Unrecognized prior service cost .......... 78.5 87.9 (106.8) 17.7 Unrecognized net transition obligation ... -- -- 92.4 101.6 ------------------------------------------------------------------------------------------- Net amount recognized .................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) =========================================================================================== Consolidated Balance Sheets classification: Prepaid (accrued) benefit cost ........... $ (548.6) $ 246.5 $ (859.5) $ (714.5) Intangible asset ......................... 78.5 -- -- -- Accumulated other comprehensive loss ..... 757.0 -- -- -- ------------------------------------------------------------------------------------------- Net amount recognized .................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) =========================================================================================== Company's share of net amount recognized .............................. $ 18.8 $ 1.6 $ (56.2) $ (119.1) ============================================================================================ Assumptions used as of December 31: Discount rate............................. 6.75% 7.25% 6.75% 7.25% Expected long-term return on plan assets . 9.00% 10.25% 9.00% 10.25% Rate of compensation increase............. 3.50% 4.00% 3.50% 4.00%
FirstEnergy's net pension and other postretirement benefit costs for the three years ended December 31, 2002 were computed as follows:
Other Pension Benefits Postretirement Benefits ------------------------ ------------------------ 2002 2001 2000 2002 2001 2000 ----------------------------------------------------------------------------------------------------- (In millions) Service cost .......................... $ 58.8 $ 34.9 $ 27.4 $ 28.5 $18.3 $11.3 Interest cost ......................... 249.3 133.3 104.8 113.6 64.4 45.7 Expected return on plan assets ........ (346.1) (204.8) (181.0) (51.7) (9.9) (0.5) Amortization of transition obligation (asset) .............................. -- (2.1) (7.9) 9.2 9.2 9.2 Amortization of prior service cost .... 9.3 8.8 5.7 3.2 3.2 3.2 Recognized net actuarial loss (gain) .. -- -- (9.1) 11.2 4.9 -- Voluntary early retirement program .... -- 6.1 17.2 -- 2.3 -- ----------------------------------------------------------------------------------------------------- Net periodic benefit cost (income) .... $ (28.7) $(23.8) $ (42.9) $114.0 $92.4 $68.9 ===================================================================================================== Company's share of net benefit cost.... $ 0.7 $ (0.7) $ (12.7) $ 4.4 $ 3.5 $15.1 -----------------------------------------------------------------------------------------------------
The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. (J) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily CEI, OE, Penn, ATSI, FirstEnergy Solutions Corp. (FES) and FirstEnergy Service Company (FECO). The Ohio transition plan, as discussed in the "Regulatory Plans" section, resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. Unregulated operations under FES now operate the generation businesses of the Company, CEI, OE and Penn. As a result, the Company entered into power supply agreements (PSA) whereby FES purchases all of the Company's nuclear generation and the generation from leased fossil generating facilities and the Company purchases its power from FES to meet its "provider of last resort" obligations. CFC serves as the transferor in connection with the accounts receivable securitization for the Company and CEI. The primary affiliated companies transactions, including the effects of the PSA beginning in 2001, the sale and leaseback of the Company's transmission assets to ATSI in September 2000 and FirstEnergy's providing support services at cost, are as follows: 2002 2001 2000 - ------------------------------------------------------------------------- (In millions) Operating Revenues: PSA revenues with FES............... $128.2 $180.9 $ -- Generating units rent with FES...... 14.0 14.0 -- Electric sales to CEI............... 104.0 97.0 106.8 Ground lease with ATSI.............. 1.7 1.7 1.9 Operating Expenses: Purchased power under PSA........... 319.0 388.0 -- Transmission expenses (including ATSI rent)....................... 22.5 17.0 9.4 FirstEnergy support services........ 26.2 23.8 36.0 Other Income: Interest income from ATSI........... 3.0 3.0 1.0 Interest income from FES............ 9.7 9.7 -- - ------------------------------------------------------------------------- FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from its affiliates, GPU Service, Inc. and FirstEnergy Service Company, both subsidiaries of FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act (PUHCA). The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas; the ratio of each company's amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers and other factors; and specific departmental charge ratios. Management believes that these allocation methods are reasonable. The Company is selling 150 megawatts of its Beaver Valley Unit 2 leased capacity entitlement to CEI. Operating revenues for this transaction were $104.0 million, $97.0 million and $104.0 million in 2002, 2001 and 2000, respectively. This sale is expected to continue through the end of the lease period. (See Note 2.) (K) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. As of December 31, 2002, cash and cash equivalents included $30 million used to redeem long-term debt in January 2003. Noncash financing and investing activities included capital lease transactions amounting to $1.0 million and $36.1 million in 2001 and 2000, respectively. There were no capital lease transactions in 2002. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt and investments other than cash and cash equivalents as of December 31:
2002 2001 - ---------------------------------------------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value - ---------------------------------------------------------------------------------------------------------- (In millions) Long-term debt....................................... $730 $772 $889 $937 Investments other than cash and cash equivalents: Debt securities - Maturity (5-10 years)........................... $123 $127 $123 $127 - Maturity (more than 10 years)................... 278 303 299 296 Equity securities................................. 2 2 2 2 All other......................................... 175 175 157 157 - ---------------------------------------------------------------------------------------------------------- $578 $607 $581 $582 ==========================================================================================================
The fair value of long-term debt reflects the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Company's ratings. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. The Company has no securities held for trading purposes. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of the Company, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "All other" in the table above) consist of equity securities, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. In conjunction with the adoption of SFAS 143 on January 1, 2003, unrealized gains or losses were reclassified to OCI in accordance with SFAS 115. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized losses were approximately $5.0 million and interest and dividend income totaled approximately $5.9 million. (L) REGULATORY ASSETS- The Company recognizes, as regulatory assets, costs which the FERC and PUCO have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets will continue to be recovered from customers under the Company's transition plan. Based on that plan, the Company continues to bill and collect cost-based rates for its transmission and distribution services, which will remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations. The Company recognized incremental transition cost recovery aggregating $24 million in 2002 and $37 million in 2001 in accordance with the current Ohio transition plan. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2002 2001 - ------------------------------------------------------------------------- (In millions) Regulatory transition costs...................... $396.5 $394.7 Loss on reacquired debt.......................... 3.0 3.2 Other............................................ (6.9) (9.1) - -------------------------------------------------------------------------- Total..................................... $392.6 $388.8 ========================================================================= 2. LEASES: The Company leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. The Company and CEI sold their ownership interests in Bruce Mansfield Units 1, 2 and 3 and the Company sold a portion of its ownership interest in Beaver Valley Unit 2. In connection with these sales, which were completed in 1987, the Company and CEI entered into operating leases for lease terms of approximately 30 years as co-lessees. During the terms of the leases, the Company and CEI continue to be responsible, to the extent of their combined ownership and leasehold interest, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company and CEI have the right, at the end of the respective basic lease terms, to renew the leases. The Company and CEI also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. As co-lessee with CEI, the Company is also obligated for CEI's lease payments. If CEI is unable to make its payments under the Bruce Mansfield Plant lease, the Company would be obligated to make such payments. No such payments have been made on behalf of CEI. (CEI's future minimum lease payments as of December 31, 2002 were approximately $0.2 billion, net of trust cash receipts.) Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2002 are summarized as follows: 2002 2001 2000 - ---------------------------------------------------------------------------- (In millions) Operating leases Interest element............... $ 52.6 $ 55.7 $ 58.7 Other.......................... 58.6 52.4 46.2 Capital leases Interest element............... -- 2.5 3.9 Other.......................... 0.3 14.1 24.1 - -------------------------------------------------------------------------- Total rentals.................. $111.5 $124.7 $132.9 ========================================================================== The future minimum lease payments as of December 31, 2002 are: Operating Leases ----------------------------------- Lease Capital Payments Trust Net - ------------------------------------------------------------------------- (In millions) 2003............................. $ 111.7 $ 36.6 $ 75.1 2004............................. 97.9 24.6 73.3 2005............................. 104.8 25.3 79.5 2006............................. 107.8 26.0 81.8 2007............................. 99.2 22.6 76.6 Years thereafter................. 908.7 228.2 680.5 ------------------------------------------------------------------------- Total minimum lease payments..... $1,430.1 $363.3 $1,066.8 ======== ====== ======== The Company and CEI refinanced high-cost fixed obligations related to their 1987 sale and leaseback transaction for the Bruce Mansfield Plant through a lower cost transaction in June and July 1997. In a June 1997 offering (Offering), the two companies pledged $720 million aggregate principal amount ($145 million for the Company and $575 million for CEI) of first mortgage bonds due through 2007 to a trust as security for the issuance of a like principal amount of secured notes due through 2007. The obligations of the two companies under these secured notes are joint and several. Using available cash, short-term borrowings and the net proceeds from the Offering, the two companies invested $906.5 million ($337.1 million for the Company and $569.4 million for CEI) in a business trust, in June 1997. The trust used these funds in July 1997 to purchase lease notes and redeem all $873.2 million aggregate principal amount of 10-1/4% and 11-1/8% secured lease obligations bonds (SLOBs) due 2003 and 2016. The SLOBs were issued by a special-purpose funding corporation in 1988 on behalf of lessors in the two companies' 1987 sale and leaseback transaction. The Shippingport Capital Trust arrangement effectively reduces lease costs related to that transaction. 3. CAPITALIZATION: (A) RETAINED EARNINGS- The Company has a provision in its mortgage that requires common stock dividends to be paid out of its total balance of retained earnings. (B) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 2002 2001 2000 - -------------------------------------------------------------------------- Restricted common shares granted ...... 36,922 133,162 208,400 Weighted average market price ......... $36.04 $35.68 $26.63 Weighted average vesting period (years) .............................. 3.2 3.7 3.8 Dividends restricted .................. Yes * Yes - --------------------------------------------------------------------------- * FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2002, there were 296,008 stock units outstanding. Stock option activities under the FE Programs for the past three years were as follows: Number of Weighted Average Stock Option Activities Options Exercise Price - ------------------------------------------------------------------------------ Balance, January 1, 2000 ............. 2,153,369 $25.32 (159,755 options exercisable) ........ 24.87 Options granted .................... 3,011,584 23.24 Options exercised .................. 90,491 26.00 Options forfeited .................. 52,600 22.20 Balance, December 31, 2000 .......... 5,021,862 24.09 (473,314 options exercisable) ........ 24.11 Options granted .................... 4,240,273 28.11 Options exercised .................. 694,403 24.24 Options forfeited .................. 120,044 28.07 Balance, December 31, 2001 ........... 8,447,688 26.04 (1,828,341 options exercisable) ...... 24.83 Options granted .................... 3,399,579 34.48 Options exercised .................. 1,018,852 23.56 Options forfeited .................. 392,929 28.19 Balance, December 31, 2002 .......... 10,435,486 28.95 (1,400,206 options exercisable) ...... 26.07 As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 1G - "Stock-Based Compensation." (C) PREFERRED AND PREFERENCE STOCK- Preferred stock may be redeemed by the Company in whole, or in part, with 30-90 days' notice. The preferred dividend rates on the Company's Series A and Series B shares fluctuate based on prevailing interest rates and market conditions. The dividend rates for both issues averaged 7% in 2002. The Company has five million authorized and unissued shares of $25 par value preference stock. (D) LONG-TERM DEBT- The Company has a first mortgage indenture under which it issues from time to time first mortgage bonds, secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Company. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) -------------------------------------------- 2003................................. $189.4 2004................................. 268.7 2005................................. 31.6 2006................................. -- 2007................................. 30.0 -------------------------------------------- Included in the table above are amounts for various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. These amounts are $73 million, $54 million and $32 million in 2003, 2004 and 2005, respectively, which represents the next date at which the debt holders may exercise this provision. The Company's obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $68.0 million and a noncancelable municipal bond insurance policy of $51.1 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letters of credit or policy, the Company is entitled to a credit against its obligation to repay those bonds. The Company pays an annual fee of 1.00% of the amounts of the letters of credit to the issuing bank and is obligated to reimburse the bank for any drawings thereunder. The Company and CEI have unsecured letters of credit of approximately $215.9 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. The Company and CEI are jointly and severally liable for the letters of credit (see Note 2). (E) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with FirstEnergy. As of December 31, 2002, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $21.1 million. 4. SHORT-TERM BORROWINGS: The Company may borrow from its affiliates on a short-term basis. As of December 31, 2002, the Company had total short-term borrowings of $149.7 million from its affiliates. The average interest rate on short-term borrowings outstanding as of December 31, 2002 and 2001, were 1.8% and 3.6%, respectively. 5. COMMITMENTS AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $169 million for property additions and improvements from 2003-2007, of which approximately $54 million is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $34 million, of which approximately $12 million applies to 2003. During the same periods, the Company's nuclear fuel investments are expected to be reduced by approximately $40 million and $19 million, respectively, as the nuclear fuel is consumed. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its ownership and leasehold interests in Beaver Valley Unit 2, the Davis Besse Station and the Perry Plant, the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $77.9 million per incident but not more than $8.8 million in any one year for each incident. The Company is also insured as to its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $263.4 million of insurance coverage for replacement power costs for its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry. Under these policies, the Company can be assessed a maximum of approximately $14.6 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Company's plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs. (C) ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. In accordance with the Ohio transition plan discussed in "Regulatory Plans" in Note 1, generation operations and any related additional capital expenditures for environmental compliance are the responsibility of FirstEnergy's competitive services business unit. The Company is required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Company cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Company believes it is in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Company's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. 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 Company's Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Company's Ohio facilities by May 31, 2004. 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 Company operates affected facilities. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. On April 25, 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. The Company has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, 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 Company's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. The Company has total accrued liabilities aggregating approximately $0.2 million as of December 31, 2002. The effects of compliance on the Company with regard to environmental matters could have a material adverse effect on the Company's earnings and competitive position. These environmental regulations affect the Company's earnings and competitive position to the extent 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. The Company 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. (D) OTHER LEGAL PROCEEDINGS- Various lawsuits, claims and proceedings related to the Company's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant applicable to the Company are described above. 6. SALE OF GENERATING ASSETS: In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 MW to NRG Energy Inc. The proposed sale had included the 648 MW Bay Shore Plant owned by the Company. On August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. 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 decided to retain ownership of these plants after reviewing other bids it subsequently received from other parties who had expressed interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, the Company reflected approximately $13 million ($8 million net of tax) of previously unrecognized depreciation and other transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statement of Income. 7. OTHER INFORMATION: The following represents the financial data which includes supplemental unaudited prior years' information as compared to consolidated financial statements and notes previously reported in 2001 and 2000: (A) Consolidated Statements of Cash Flows 2002 2001 2000 ---- ---- ---- (In Thousands) Other Cash Flows from Operating Activities: Accrued taxes............................... $ (4,881) $(17,671) $ 223 Accrued interest............................ (3,541) (28) (2,015) Prepayments and other....................... 11,125 12,571 (1,220) All other................................... (8,614) (46,653) (34,722) -------- -------- -------- Other cash used for operating activities.. $ (5,911) $(51,781) $(38,180) ======== ======== ======== (B) Consolidated Statements of Taxes 2002 2001 2000 ---- ---- ---- (In Thousands) Other Accumulated Deferred Income Taxes at December 31: Retirement Benefits......................... $ (9,768) $(35,126) $(28,656) All other................................... (53,529) (63,288) (1,742) -------- -------- -------- Total-Other............................... $(63,297) $(98,414) $(30,398) ======== ======== ======== 8. RECENTLY ISSUED ACCOUNTING STANDARDS: FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002 (see Guarantees and Other Assurances). It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions beginning in the first interim or annual reporting period after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. We currently have transactions with entities which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. The Company currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. One of these entities it is currently consolidating is the Shippingport Capital Trust which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of its interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated parties and 0.34 percent equity interest by Toledo Edison Capital Corp., a majority owned subsidiary. 9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
March 31, June 30, September 30, December 31, Three Months Ended 2002 2002 2002 2002 - ------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues.......................... $244.1 $250.3 $269.9 $223.3 Operating Expenses and Taxes................ 234.5 216.2 244.8 236.9 - ------------------------------------------------------------------------------------------------------------- Operating Income (Loss)..................... 9.6 34.1 25.1 (13.6) Other Income (Expense)...................... 4.4 3.7 4.0 1.1 Net Interest Charges........................ 14.7 14.8 14.5 11.2 - ------------------------------------------------------------------------------------------------------------- Net Income (Loss)........................... $ (0.7) $ 23.0 $ 14.6 $(23.7) ============================================================================================================= Earnings (Loss) Applicable to Common Stock.. $ 5.4 $ 20.8 $ 12.4 $(25.8) ============================================================================================================= March 31, June 30, September 30, December 31, Three Months Ended 2001 2001 2001 2001 - ------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues.......................... $271.6 $263.0 $306.5 $253.8 Operating Expenses and Taxes................ 243.3 229.6 278.9 237.6 - ------------------------------------------------------------------------------------------------------------- Operating Income............................ 28.3 33.4 27.6 16.2 Other Income................................ 3.8 2.2 3.9 5.7 Net Interest Charges........................ 15.9 12.6 15.1 14.6 - ------------------------------------------------------------------------------------------------------------- Net Income.................................. $ 16.2 $ 23.0 $ 16.4 $ 7.3 ============================================================================================================= Earnings on Common Stock.................... $ 12.2 $ 18.9 $ 12.4 $ 3.3 =============================================================================================================
Report of Independent Accountants To the Stockholders and Board of Directors of The Toledo Edison Company: In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of The Toledo Edison Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiary as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The consolidated financial statements of The Toledo Edison Company and subsidiary as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financials statements, before the revisions described in Note 1 to the 2002 consolidated financial statements, in their report dated March 18, 2002. As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for goodwill in 2002. As discussed above, the consolidated financial statements of The Toledo Edison Company and subsidiary as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent accountants who have ceased operations. As described in Note 1 to the consolidated financial statements, revisions have been made to include the transitional disclosures required by Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, which was adopted by the Company as of January 1, 2002. In our opinion the transitional disclosures for 2001 and 2000 are appropriate. However, we were not engaged to audit, review, or apply any procedures to the 2001 and 2000 consolidated financial statements of the Company other than with respect to such disclosures and, accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 consolidated financial statements taken as a whole. PricewaterhouseCoopers LLP Cleveland, Ohio February 28, 2003 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. Report of Independent Public Accountants To the Stockholders and Board of Directors of The Toledo Edison Company: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Toledo Edison Company (an Ohio corporation and wholly owned subsidiary of FirstEnergy Corp.) and subsidiary as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Toledo Edison Company and subsidiary as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. EX-21 26 te_ex21-3.txt EX. 21-3 LIST OF SUBS - TE EXHIBIT 21.3 THE TOLEDO EDISON COMPANY LIST OF SUBSIDIARIES OF THE REGISTRANT AT DECEMBER 31, 2002 The Toledo Edison Capital Corporation - Incorporated in Delaware Statement of Differences ------------------------ Exhibit Number 21, List of Subsidiaries of the Registrant at December 31, 2002, is not included in the printed document. EX-12 27 pp_ex12-5.txt EX. 12-5 FIXED CHARGE RATIO - PENN
EXHIBIT 12.5 Page 1 PENNSYLVANIA POWER COMPANY RATIO OF EARNINGS TO FIXED CHARGES Year Ended December 31, ----------------------------------------------------------- 1998 1999 2000 2001 2002 ------- ------- ------- -------- -------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items......................... $39,748 $12,648 $22,847 $ 41,041 $ 47,717 Interest before reduction for amounts capitalized......... 21,073 21,317 20,437 18,172 16,674 Provision for income taxes................................ 32,504 18,834 26,121 39,921 43,044 Interest element of rentals charged to income (a)......... 1,920 1,887 2,791 1,316 326 ------- ------- ------- -------- -------- Earnings as defined..................................... $95,245 $54,686 $72,196 $100,450 $107,761 ======= ======= ======= ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K: Interest on long-term debt................................ $19,255 $19,268 $18,651 $ 16,971 $ 15,521 Interest on nuclear fuel obligations...................... 28 90 364 141 8 Other interest expense.................................... 1,789 1,959 1,422 1,060 1,145 Interest element of rentals charged to income (a)......... 1,920 1,887 2,791 1,316 326 ------- ------- ------- -------- -------- Fixed charges as defined................................ $22,992 $23,204 $23,228 $ 19,488 $ 17,000 ======= ======= ======= ======== ======== RATIO OF EARNINGS TO FIXED CHARGES (b)....................... 4.14 2.36 3.11 5.15 6.34 ==== ==== ==== ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined. (b) These ratios exclude fixed charges applicable to the guarantee of the debt of a coal supplier aggregating $483,000 for the year ended December 31, 1998. The guarantee and related coal supply contract debt expired December 31, 1999.
EXHIBIT 12.5 Page 2 PENNSYLVANIA POWER COMPANY RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS) Year Ended December 31, ----------------------------------------------------------- 1998 1999 2000 2001 2002 ------- ------- ------- -------- -------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items......................... $39,748 $12,648 $22,847 $ 41,041 $ 47,717 Interest before reduction for amounts capitalized......... 21,073 21,317 20,437 18,172 16,674 Provision for income taxes................................ 32,504 18,834 26,121 39,921 43,044 Interest element of rentals charged to income (a)......... 1,920 1,887 2,791 1,316 326 ------- ------- -------- -------- -------- Earnings as defined..................................... $95,245 $54,686 $72,196 $100,450 $107,761 ======= ======= ======= ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS): Interest on long-term debt................................ $19,255 $19,268 $18,651 $ 16,971 $ 15,521 Interest on nuclear fuel obligations...................... 28 90 364 141 8 Other interest expense.................................... 1,789 1,959 1,422 1,060 1,145 Preferred stock dividend requirements..................... 4,626 4,370 3,704 3,703 3,699 Adjustment to preferred stock dividends to state on a pre-income tax basis 3,726 6,403 4,018 3,534 3,274 Interest element of rentals charged to income (a)......... 1,920 1,887 2,791 1,316 326 ------- ------- ------- -------- -------- Fixed charges as defined plus preferred stock dividend requirements (pre-income tax basis).......... $31,344 $33,977 $30,950 $ 26,725 $ 23,973 ======= ======= ======= ======== ======== RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS) (b).... 3.04 1.61 2.33 3.76 4.50 ==== ==== ==== ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined. (b) These ratios exclude fixed charges applicable to the guarantee of the debt of a coal supplier aggregating $483,000 for the year ended December 31, 1998. The guarantee and related coal supply contract debt expired December 31, 1999.
EX-13 28 pp_ex13-4.txt EX. 13-4 ANNUAL REPORT - PENN PENNSYLVANIA POWER COMPANY 2002 ANNUAL REPORT TO STOCKHOLDERS Pennsylvania Power Company (Penn), an electric utility operating company of FirstEnergy Corp. and a wholly owned subsidiary of Ohio Edison Company, provides electric service to approximately 155,000 customers in western Pennsylvania. Contents Page - -------- ---- Selected Financial Data......................................... 1 Management's Discussion and Analysis............................ 2-10 Statements of Income............................................ 11 Balance Sheets.................................................. 12 Statements of Capitalization.................................... 13 Statements of Common Stockholder's Equity....................... 14 Statements of Preferred Stock................................... 14 Statements of Cash Flows........................................ 15 Statements of Taxes............................................. 16 Notes to Financial Statements................................... 17-27 Reports of Independent Accountants.............................. 28-29
PENNSYLVANIA POWER COMPANY SELECTED FINANCIAL DATA 2002 2001 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- (Dollars in thousands) Operating Revenues...................... $506,407 $498,401 $383,112 $ 329,234 $323,756 ======== ======== ======== ========== ======== Operating Income........................ $ 60,922 $ 55,178 $ 39,979 $ 32,063 $ 58,041 ======== ======== ======== ========== ======== Income Before Extraordinary Item........ $ 47,717 $ 41,041 $ 22,847 $ 12,648 $ 39,748 ======== ======== ======== ========== ======== Net Income.............................. $ 47,717 $ 41,041 $ 22,847 $ 12,648 $ 9,226 ======== ======== ======== ========== ======== Earnings on Common Stock................ $ 44,018 $ 37,338 $ 19,143 $ 8,278 $ 4,600 ======== ======== ======== ========== ======== Total Assets............................ $907,748 $960,097 $988,909 $1,015,616 $977,772 ======== ======== ======== ========== ======== CAPITALIZATION AT DECEMBER 31: Common Stockholder's Equity............. $229,374 $223,788 $213,851 $ 199,608 $275,281 Preferred Stock- Not Subject to Mandatory Redemption.. 39,105 39,105 39,105 39,105 50,905 Subject to Mandatory Redemption...... 13,500 14,250 15,000 15,000 15,000 Long-Term Debt.......................... 185,499 262,047 270,368 274,821 287,689 -------- -------- -------- ---------- -------- Total Capitalization.................... $467,478 $539,190 $538,324 $ 528,534 $628,875 ======== ======== ======== ========== ======== CAPITALIZATION RATIOS: Common Stockholder's Equity............. 49.1% 41.5% 39.7% 37.8% 43.8% Preferred Stock- Not Subject to Mandatory Redemption.. 8.3 7.3 7.3 7.4 8.1 Subject to Mandatory Redemption...... 2.9 2.6 2.8 2.8 2.4 Long-Term Debt.......................... 39.7 48.6 50.2 52.0 45.7 ----- ----- ----- ----- ----- Total Capitalization.................... 100.0% 100.0% 100.0% 100.0% 100.0% ===== ===== ===== ===== ===== DISTRIBUTION KILOWATT-HOUR DELIVERIES (Millions): Residential............................. 1,533 1,391 1,387 1,325 1,278 Commercial.............................. 1,268 1,220 1,198 1,105 1,069 Industrial.............................. 1,505 1,540 1,665 1,495 1,439 Other................................... 6 6 6 6 6 ----- ------ ----- ----- ----- Total................................... 4,312 4,157 4,256 3,931 3,792 ===== ===== ===== ===== ===== CUSTOMERS SERVED: Residential............................. 136,410 134,956 121,066 117,440 124,304 Commercial.............................. 18,397 18,153 16,634 16,307 16,924 Industrial.............................. 220 224 177 175 206 Other................................... 85 87 87 87 86 ------- ------- ------- ------- ------- Total................................... 155,112 153,420 137,964 134,009 141,520 ======= ======= ======= ======= ======= NUMBER OF EMPLOYEES..................... 201 256 275 895 888 1
PENNSYLVANIA POWER COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Corporate Separation - -------------------- In connection with FirstEnergy's Ohio transition plan, FirstEnergy separated its businesses into three distinct units - a competitive services segment, a regulated services segment and a corporate support services segment. Pennsylvania Power Company (Penn) is included in the regulated services segment which continues to deliver power to homes and businesses through its existing distribution system and maintains the "provider of last resort" (PLR) obligation under its rate plan. Beginning on January 1, 2001, FirstEnergy's electric utility operating companies (EUOC) entered into power supply agreements whereby FirstEnergy Solutions Corp. (FES) purchases all of the EUOC nuclear generation, as well as generation from leased fossil generation facilities. FirstEnergy Generation Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil generating units owned by the EUOC. We are a "full requirements" customer of FES to enable us to meet our PLR responsibilities in our service area. The effect on Penn's reported results of operations in 2001 from FirstEnergy's corporate separation plan and our sale of transmission assets to American Transmission Systems, Inc. (ATSI) in September 2000, are summarized in the following table:
Corporate Restructuring - 2001 Income Statement Effects ------------------------------------------------------- Increase (Decrease) Corporate Separation ATSI Total ---------- ---- ----- (In millions) Operating Revenues: Power supply agreement with FES........ $151.5 $ -- $151.5 Generating units rent.................. 20.2 -- 20.2 Ground lease with ATSI................. -- 0.6 0.6 -------------------------------------------------------------------------------------- Total Operating Revenues Effect........ $171.7 $ 0.6 $172.3 ====================================================================================== Operating Expenses and Taxes: Fossil fuel costs...................... $(32.6)(a) $ -- $(32.6) Purchased power costs.................. 152.7(b) -- 152.7 Other operating costs.................. (21.1)(a) 4.9 (d) (16.2) Provision for depreciation and amortization ........................ -- (2.2)(e) (2.2) General taxes.......................... (2.4)(c) (0.3)(e) (2.7) Income Taxes........................... 31.1 -- 31.1 -------------------------------------------------------------------------------------- Total Operating Expenses Effect........ $127.7 $ 2.4 $130.1 ====================================================================================== Other Income............................. $ -- $ 1.7 (f) $ 1.7 ====================================================================================== (a) Transfer of fossil operations to FGCO. (b) Purchased power from power supply agreement (PSA). (c) Payroll taxes related to employees transferred to FGCO. (d) Transmission services received from ATSI. (e) Depreciation and property taxes related to transmission assets sold to ATSI. (f) Interest on note receivable from ATSI.
Results of Operations - --------------------- Earnings on common stock in 2002 increased 17.9% to $44.0 million from $37.3 million in 2001. The earnings increase in 2002 primarily resulted from increased operating revenues and lower financing costs, which were partially offset by higher operating expenses and taxes and reduced other income. Excluding the effects shown in the table 2 above, earnings on common stock decreased to $6.6 million in 2001 from 2000, being adversely affected by reduced operating revenues, which were partially offset by lower operating expenses, taxes and net interest charges. Operating revenues increased by $8.0 million or 1.6% in 2002 as compared to 2001. The return of customers previously served by alternative generation suppliers contributed to the revenue increase. Retail kilowatt-hour sales increased by 7.8% in 2002 from the prior year, with increases in the residential and commercial sectors contributing to a $15.8 million increase in generation sales revenue. Sales of electric generation by alternative suppliers as a percent of total sales delivered in our franchise area decreased to 0.4% in 2002 from 4.1% in 2001. Distribution deliveries increased 3.7% in 2002 as compared to 2001, which increased revenues from electricity throughput by $3.9 million in 2002 from the prior year. The higher distribution deliveries resulted from additional residential and commercial demand due to warmer summer weather that was offset in part by the effect of continued sluggishness in the economy on demand by industrial customers. Sales revenues from wholesale customers decreased by $14.3 million in 2002 compared to 2001, due to a decline in market prices. Excluding the effects shown in the table above, operating revenues decreased by $57.0 million or 14.9% in 2001 from 2000. The decrease primarily resulted from a $56.7 million reduction in wholesale revenues (a 93.3% decrease in wholesale kilowatt-hour sales) from the prior year due to the substitution of PSA sales for kilowatt-hour sales to other wholesale customers. Distribution deliveries declined 2.3% in 2001 from 2000 reflecting the influence of a declining national economy on our regional business activity that contributed to lower distribution deliveries to commercial and industrial customers. Partially offsetting the impact of a weaker economy was an increase in retail electric generation revenues reflecting a return of customers previously served by alternative generation suppliers. Retail generation sales increased in all customer categories resulting in an overall 4.8% increase in kilowatt-hour sales in 2001 from the prior year. Electric generation services provided by other suppliers in our service area decreased to 4.1% in 2001 from 10.6% in 2000. Changes in KWH Sales 2002 2001 ------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ 7.8% 4.8% Wholesale............................. 12.0% (93.3)% ------------------------------------------------------------------- Total Electric Generation Sales......... 10.3% (62.6)% =================================================================== Distribution Deliveries: Residential........................... 10.2% 0.3% Commercial and industrial............. 0.5% (3.6)% ------------------------------------------------------------------- Total Distribution Deliveries........... 3.7% (2.3)% =================================================================== Operating Expenses and Taxes Total operating expenses and taxes increased by $2.3 million in 2002 and by $100.1 million in 2001 from the prior year. Excluding the effects of restructuring, total 2001 operating expenses and taxes were $30.0 million lower than 2000. The following table presents changes from the prior year by expense category excluding the impact of restructuring. Operating Expenses and Taxes - Changes 2002 2001 ------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel and purchased power...................... $ 6.7 $(12.9) Nuclear operating costs....................... (24.6) 1.9 Other operating costs......................... 5.4 1.9 -------------------------------------------------------------------- Total operation and maintenance expenses.... (12.5) (9.1) Provision for depreciation and amortization... (0.3) 3.3 General taxes................................. 10.3 (5.2) Income taxes.................................. 4.8 (19.0) --------------------------------------------------------------------- Total operating expenses and taxes.......... $ 2.3 $(30.0) ===================================================================== Higher fuel and purchased power costs in 2002 compared with 2001, resulted from a $4.2 million increase in power purchased from FES, reflecting higher kilowatt-hours purchased due to increased kilowatt-hour sales and lower unit prices. Nuclear operating costs decreased $24.6 million, primarily due to one less refueling outage in 2002 compared to 2001. The $5.4 million increase in other operating costs resulted principally from higher employee benefit costs. 3 The decrease in fuel and purchased power costs in 2001 compared to 2000, primarily reflects the transfer of fossil operations to FGCO with our power requirements being provided under the PSA. Nuclear operating costs increased slightly in 2001 from the previous year. In 2001, depreciation and amortization increased $3.3 million compared with 2000 primarily from the absence in 2001 of an adjustment in 2000 related to decommissioning costs. General taxes increased by $10.3 million in 2002 from 2001 as a result of additional property taxes and gross receipt taxes. In 2001, general taxes decreased by $5.2 million in 2001 from 2000 primarily due to a one-time benefit of $3 million resulting from successfully resolving certain pending tax issues and the effect of a reduction to the gross receipts tax rate. Net Interest Charges Net interest charges continued to trend lower, decreasing by $2.2 million in 2002 and by $2.1 million in 2001, compared to the prior year. We continue to redeem and refinance outstanding debt during 2002 - net redemptions and refinancing activities totaled $1.7 million and $14.5 million, respectively, and will result in annualized savings of $523,000. Capital Resources and Liquidity - ------------------------------- Through net debt and preferred stock redemptions, we continue to reduce the cost of debt and preferred stock, and improve our financial position in 2002. During 2002, we reduced our total debt by approximately $40.1 million. At the end of 2002, our common equity as a percentage of capitalization stood at 49% compared to 42% at the end of 2001. The higher common equity percentage in 2002 compared to 2001 resulted from net redemptions of preferred stock and long-term debt and the increase in retained earnings. Changes in Cash Position As of December 31, 2002, we had $1.2 million of cash and cash equivalents, compared with $0.1 million as of December 31, 2001. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Our net cash from operating activities is provided by our regulated energy services. Net cash provided from operating activities was $105.8 million in 2002 and $93.3 million in 2001. Cash provided from 2002 and 2001 operating activities are as follows: Operating Cash Flows 2002 2001 ------------------------------------------------------------- (In millions) Cash earnings (1).................. $115.8 $101.6 Working capital and other.......... (10.0) (8.3) ------------------------------------------------------------- Total.............................. $105.8 $93.3 ============================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Cash Flows From Financing Activities In 2002, the net cash used for financing activities of $75.3 million primarily reflects the redemptions of debt and preferred stock shown below. The following table provides details regarding new issues and redemptions during 2002: Securities Issued or Redeemed in 2002 -------------------------------------------------------------- (In millions) New Issues ---------- Pollution Control Notes..................... $ 14.5 Redemptions ----------- First Mortgage Bonds........................ 1.0 Pollution Control Notes..................... 14.5 Capital Fuel Leases......................... 40.7 Preferred Stock............................. 0.8 Other, principally redemption premiums...... 0.6 ----------------------------------------------------------- $ 57.6 4 In 2001, net cash flow used for financing activities totaled $50.8 million, primarily due to $51 million of long-term debt redemptions and $31 million of dividend payments. We had about $36.5 million of cash and temporary investments and no short-term indebtedness as of December 31, 2002. At the end of 2002, we had the capability to issue $323 million of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon applicable earnings in 2002 under the earnings coverage test contained in our charter, we could issue $251 million of preferred stock (assuming no additional debt was issued). Cash Flows From Investing Activities Net cash used in investing activities totaled $29.3 million in 2002. The net cash used for investing resulted from loan payments from OE, which were offset in part by an increase in property additions. Expenditures for property additions primarily include expenditures supporting our distribution of electricity. In 2001, net cash used in investing activities totaled $45.9 million, principally due to property additions and loans to associated companies, which were offset in part by sales of assets to associated companies. Our cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Major contractual obligations for future cash payments are summarized in the following table:
Less than 1-3 3-5 More than Contractual Obligations Total 1 Year Years Years 5 Years - --------------------------------------------------------------------------------------------------------------- (in millions) Long-term debt.................. $251 $41 $36 $ 2 $172 Preferred stock (1)............. 14 1 2 11 -- Purchases (2)................... 89 21 17 29 22 - ------------------------------------------------------------------------------------------------------------- Total........................ $354 $63 $55 $42 $194 ============================================================================================================= (1) Subject to mandatory redemption. (2) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.
Our capital spending for the period 2003-2007 is expected to be about $123 million (excluding nuclear fuel) of which approximately $53 million applies to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $42 million, of which about $19 million relates to 2003. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $34 million and $17 million, respectively, as the nuclear fuel is consumed. We had no other material obligations as of December 31, 2002 that have not been recognized on our Balance Sheet. On February 22, 2002, Moody's Investor Service changed its credit rating outlook for FirstEnergy from stable to negative. The change was based upon a decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania Public Utility Commission (PPUC) for reconsideration its decision on the mechanism for sharing merger savings and reversed the PPUC's decisions regarding rate relief and accounting deferrals rendered in connection with its approval of the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed its outlook for FirstEnergy's credit ratings from stable to negative citing recent developments including: damage to the Davis-Besse reactor vessel head (the Company has no ownership interest in Davis-Besse), the Pennsylvania Commonwealth Court decision, and deteriorating market conditions for some sales of its remaining non-core assets. On July 31, 2002, Fitch revised its rating outlook for FirstEnergy, negative from stable. The revised outlook reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's judgment about NRG's financial ability to consummate the purchase of four power plants (none owned by the Company) from FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while NRG's liquidity position added uncertainty to FirstEnergy's sale of power plants to NRG, its ratings would not be affected. S&P found FirstEnergy's cash flows sufficiently stable to support a continued (although delayed) program of debt and preferred stock redemption. S&P noted that they would continue to closely monitor FirstEnergy's progress on various initiatives. On January 21, 2003, S&P indicated its concern about FirstEnergy's disclosure of noncash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa (FirstEnergy's Argentina operations), which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining its current debt ratings. S&P also identified other issues it would continue to monitor including: its deleveraging efforts, free cash generated during 2003, the Jersey Central Power & Light Company rate case, successful hedging of its short power position, and continued capture of projected merger savings. While FirstEnergy anticipates being prepared to restart the Davis-Besse plant in the spring of 2003, the Nuclear Regulatory Commission (NRC) must authorize the unit's restart following a formal inspection process prior to its returning the unit to service. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt could put additional pressure on Penn's credit ratings. 5 Interest Rate Risk - ------------------ Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the following table. We are subject to the inherent risks related to refinancing maturing debt by issuing new debt securities. Changes in the market value of our nuclear decommissioning trust funds had been recognized by making corresponding changes to the decommissioning liability, as described in Note 1 - Utility Plant and Depreciation. In conjunction with the adoption of SFAS 143, "Accounting for Asset Retirement Obligations," on January 1, 2003, we reclassified unrealized gains and losses to other comprehensive income (OCI) in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity." While fluctuations in the fair value of our Ohio EUOCs' trust balances will eventually affect earnings (affecting OCI initially) based on the guidance provided by SFAS 115, our non-Ohio EUOC have the opportunity to recover from customers the difference between the investments held in trust and their decommissioning obligations. Thus, in absence of disallowed costs, there should be no earnings effect from fluctuations in their decommissioning trust balances. As of December 31, 2002, decommissioning trust balances totaled $1.050 billion, with $698 million held by our Ohio EUOC and the balance held by our non-Ohio EUOC. As of year end 2002, trust balances included 51% of equity and 49% of debt instruments. The table below presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.
Comparison of Carrying Value to Fair Value - ------------------------------------------------------------------------------------------------------------------- There- Fair 2003 2004 2005 2006 2007 after Total Value - -------------------------------------------------------------------------------------------------------------------- (Dollars in millions) Assets - -------------------------------------------------------------------------------------------------------------------- Investments other than Cash and Cash Equivalents: Fixed Income................. $ 6 $ 1 $ 1 $115 $123 $127 Average interest rate..... 7.8% 7.8% 7.8% 5.5% 5.7% - -------------------------------------------------------------------------------------------------------------------- Liabilities - -------------------------------------------------------------------------------------------------------------------- Long-term Debt: Fixed rate................... $41 $ 35 $ 1 $ 1 $ 1 $110 $189 $198 Average interest rate .... 7.6% 6.6% 9.7% 9.7% 9.7% 7.0% 7.1% Variable rate................ $ 62 $ 62 $ 62 Average interest rate..... 2.4% 2.4% Preferred Stock.............. $ 1 $ 1 $ 1 $ 1 $10 $ 14 $ 14 Average dividend rate .... 7.6% 7.6% 7.6% 7.6% 7.6% 7.6% - -------------------------------------------------------------------------------------------------------------------
Equity Price Risk - ----------------- Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $38 million and $47 million as of December 31, 2002 and 2001, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $4 million reduction in fair value as of December 31, 2002 (see Note 1 - Supplemental Cash Flows Information). Outlook - ------- In 2002, a number of our customers previously electing to be served by alternative energy providers returned to our system for their energy needs. We have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. We continue to deliver power to homes and businesses through our existing distribution system, which remains regulated. As part of our transition plan we are obligated to supply electricity to customers who do not choose an alternative supplier. Our competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in our franchise area. In 2003, the total peak load forecasted for customers electing to stay with us, including the load served by our affiliate is 955 megawatts (MW). 6 Environmental Matters We believe we are in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 5 - Environmental Matters). We continue to evaluate our compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W.H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against 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 (CAA). The civil complaint against OE and Penn requests installation of "best available control technology" as well as civil penalties of up to $27,500 per day. Although unable to predict the outcome of these proceedings, we believe the Sammis Plant is in full compliance with the CAA and that the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. 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 effects of compliance on the Company with regard to environmental matters could have a material adverse effect on our earnings and competitive position. These environmental regulations affect our earnings and competitive position to the extent we compete with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. We believe we are in material compliance with existing regulations, but are unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Significant Accounting Policies - ------------------------------- We prepare our financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect our financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. Our more significant accounting policies are described below. Regulatory Accounting We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on our costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded -- $157 million as of December 31, 2002. We continually review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. 7 Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet been billed through the end of the year. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, we reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000. Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. The market values of our pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002, 2001 and 2000, plan assets have earned (11.3)%, (5.5)% and (0.3)%, respectively. Our pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, we will not be required to fund our pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to our 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. 8 The effect on our SFAS 87 and 106 costs and liabilities from changes in key assumptions are as follows: Increase in Costs from Adverse Changes in Key Assumptions - ------------------------------------------------------------------------------- Assumption Adverse Change Pension OPEB Total - ------------------------------------------------------------------------------- (In millions) Discount rate Decrease by 0.25% $0.1 $0.1 $0.2 Long-term return on assets Decrease by 0.25% 0.1 -- 0.1 Health care trend rate Increase by 1% na 0.2 0.2 Increase in Minimum Pension Liability - ------------------------------------- Discount rate Decrease by 0.25% 2.0 na 2.0 - ------------------------------------------------------------------------------- As a result of the reduced market value of our pension plan assets, we were required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. We eliminated our prepaid pension asset of $8.8 million and established a minimum liability of $11.7 million, recording an intangible asset of $3.6 million and reducing OCI by $9.9 million (recording a related deferred tax benefit of $7.0 million). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002 increased due to the lower discount rate assumed and reduced market value of plan assets as of December 31, 2002. Our non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $1.1 million and $0.4 million, respectively - a total of $1.5 million in 2003 as compared to 2002. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset, is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- SFAS 143, "Accounting for Asset Retirement Obligations" In June 2001, the FASB issued SFAS 143. The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize regulatory assets or liabilities if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. We have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $78 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $9 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144. No impairment was indicated. The asset retirement liability at the date of adoption was $121 million. As of December 31, 2002, Penn had recorded decommissioning liabilities of $120 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that substantially all nuclear decommissioning costs for Penn will be recoverable through its regulated rates. Therefore, we recognized a regulatory liability of $69 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities for Penn was a $1.1 million decrease to income ($0.6 million net of tax). 9 SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities" This statement, which was issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time they are incurred rather than when management commits to a plan of exit or disposal. It also requires the use of fair value for the measurement of such liabilities. The new standard supersedes guidance provided by EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This new standard was effective for exit and disposal activities initiated after December 31, 2002. Since it is applied prospectively, there will be no impact upon adoption. However, SFAS 146 could change the timing and amount of costs recognized in connection with future exit or disposal activities. FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. 10
PENNSYLVANIA POWER COMPANY STATEMENTS OF INCOME For the Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- (In thousands) OPERATING REVENUES (Note 1)............................................... $506,407 $498,401 $383,112 -------- -------- -------- OPERATING EXPENSES AND TAXES: Fuel and purchased power (Note 1)...................................... 181,968 175,257 68,099 Nuclear operating costs (Note 1)....................................... 90,024 114,623 112,731 Other operating costs (Note 1)......................................... 50,523 45,133 59,389 -------- -------- -------- Total operation and maintenance expenses............................. 322,515 335,013 240,219 Provision for depreciation and amortization............................ 56,763 57,087 55,964 General taxes.......................................................... 24,474 14,214 22,076 Income taxes........................................................... 41,733 36,909 24,874 -------- -------- -------- Total operating expenses and taxes................................... 445,485 443,223 343,133 -------- -------- -------- OPERATING INCOME.......................................................... 60,922 55,178 39,979 OTHER INCOME (Note 1)..................................................... 1,960 3,185 2,300 -------- -------- -------- INCOME BEFORE NET INTEREST CHARGES........................................ 62,882 58,363 42,279 -------- -------- -------- NET INTEREST CHARGES: Interest on long-term debt............................................. 15,521 16,971 18,651 Interest on nuclear fuel obligations................................... 8 141 364 Allowance for borrowed funds used during construction.................. (1,509) (850) (1,005) Other interest expense................................................. 1,145 1,060 1,422 -------- -------- -------- Net interest charges................................................. 15,165 17,322 19,432 -------- -------- -------- NET INCOME................................................................ 47,717 41,041 22,847 PREFERRED STOCK DIVIDEND REQUIREMENTS..................................... 3,699 3,703 3,704 -------- -------- -------- EARNINGS ON COMMON STOCK.................................................. $ 44,018 $ 37,338 $ 19,143 ======== ======== ======== The accompanying Notes to Financial Statements are an integral part of these statements.
11
PENNSYLVANIA POWER COMPANY BALANCE SHEETS As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------ (In thousands) ASSETS UTILITY PLANT: In service........................................................................ $680,729 $664,432 Less-Accumulated provision for depreciation....................................... 316,424 290,216 -------- -------- 364,305 374,216 -------- -------- Construction work in progress- Electric plant................................................................. 44,696 24,141 Nuclear fuel................................................................... 8,812 2,921 -------- -------- 53,508 27,062 -------- -------- 417,813 401,278 -------- -------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts (Note 1)..................................... 119,401 116,634 Long-term notes receivable from associated companies.............................. 38,921 39,290 Other (Note 1H)................................................................... 2,569 21,597 -------- -------- 160,891 177,521 -------- -------- CURRENT ASSETS: Cash and cash equivalents......................................................... 1,222 67 Notes receivable from associated companies........................................ 35,317 54,411 Receivables- Customers (less accumulated provisions of $702,000 and $619,000, respectively, for uncollectible accounts).................................... 44,341 40,890 Associated companies........................................................... 42,652 36,491 Other.......................................................................... 5,262 4,787 Materials and supplies, at average cost........................................... 30,309 25,598 Prepayments....................................................................... 5,346 5,682 -------- -------- 164,449 167,926 -------- -------- DEFERRED CHARGES: Regulatory assets................................................................. 156,903 208,838 Other............................................................................. 7,692 4,534 -------- -------- 164,595 213,372 -------- -------- $907,748 $960,097 ======== ======== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Statements of Capitalization): Common stockholder's equity....................................................... $229,374 $223,788 Preferred stock- Not subject to mandatory redemption............................................ 39,105 39,105 Subject to mandatory redemption................................................ 13,500 14,250 Long-term debt- Associated companies........................................................... -- 21,064 Other.......................................................................... 185,499 240,983 -------- -------- 467,478 539,190 -------- -------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock- Associated companies........................................................... -- 18,090 Other.......................................................................... 66,556 12,075 Accounts payable- Associated companies........................................................... 52,653 50,604 Other.......................................................................... 5,730 1,441 Accrued taxes..................................................................... 12,507 18,853 Accrued interest.................................................................. 5,558 5,264 Other............................................................................. 10,479 9,675 -------- -------- 153,483 116,002 -------- -------- DEFERRED CREDITS: Accumulated deferred income taxes................................................. 117,385 136,808 Accumulated deferred investment tax credits....................................... 3,810 4,108 Nuclear plant decommissioning costs............................................... 119,863 117,096 Other............................................................................. 45,729 46,893 -------- -------- 286,787 304,905 -------- -------- COMMITMENTS AND CONTINGENCIES (Notes 2 and 5)..................................... -------- -------- $907,748 $960,097 ======== ======== The accompanying Notes to Financial Statements are an integral part of these balance sheets.
12 PENNSYLVANIA POWER COMPANY STATEMENTS OF CAPITALIZATION
As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------ (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, $30 par value, 6,500,000 shares authorized, 6,290,000 shares outstanding $188,700 $188,700 Other paid-in capital................................................................ (310) (310) Accumulated other comprehensive loss (Note 3F)....................................... (9,932) -- Retained earnings (Note 3A).......................................................... 50,916 35,398 -------- -------- Total common stockholder's equity.................................................. 229,374 223,788 -------- -------- Number of Shares Optional Outstanding Redemption Price ---------------- ------------------- 2002 2001 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK (Note 3C): Cumulative, $100 par value- Authorized 1,200,000 shares Not Subject to Mandatory Redemption: 4.24%................................ 40,000 40,000 $103.13 $ 4,125 4,000 4,000 4.25%................................ 41,049 41,049 105.00 4,310 4,105 4,105 4.64%................................ 60,000 60,000 102.98 6,179 6,000 6,000 7.75%................................ 250,000 250,000 -- -- 25,000 25,000 ------- ------- ------- ------- -------- Total not subject to mandatory redemption....................... 391,049 391,049 $14,614 39,105 39,105 ======= ======= ======= ------- -------- Subject to Mandatory Redemption (Note 3D): 7.625%............................... 142,500 150,000 103.81 $14,793 14,250 15,000 Redemption Within One Year............. (750) (750) ------- ------- ------- ------- -------- Total subject to mandatory redemption 142,500 150,000 $14,793 13,500 14,250 ======= ======= ======= ------- -------- LONG-TERM DEBT (Note 3E): First mortgage bonds- 9.740% due 2003-2019............................................................... 16,591 17,565 7.500% due 2003.................................................................... 40,000 40,000 6.375% due 2004.................................................................... 20,500 20,500 6.625% due 2004.................................................................... 14,000 14,000 8.500% due 2022.................................................................... 27,250 27,250 7.625% due 2023.................................................................... 6,500 6,500 -------- -------- Total first mortgage bonds....................................................... 124,841 125,815 -------- -------- Secured notes- 5.400% due 2013.................................................................... 1,000 1,000 5.400% due 2017.................................................................... 10,600 10,600 *1.350% due 2017.................................................................... 17,925 17,925 5.900% due 2018.................................................................... 16,800 16,800 *1.350% due 2021.................................................................... 14,482 14,482 6.150% due 2023.................................................................... 12,700 12,700 *1.600% due 2027.................................................................... 10,300 10,300 6.450% due 2027.................................................................... -- 14,500 5.375% due 2028.................................................................... 1,734 1,734 5.450% due 2028.................................................................... 6,950 6,950 6.000% due 2028.................................................................... 14,250 14,250 5.950% due 2029.................................................................... 238 238 -------- --------- Total secured notes.............................................................. 106,979 121,479 -------- -------- Unsecured notes- *5.900% due 2033.................................................................... 5,200 5,200 *3.850% due 2029.................................................................... 14,500 -- -------- -------- Total unsecured notes............................................................ 19,700 5,200 -------- -------- Other obligations- Nuclear fuel....................................................................... -- 39,154 Capital leases (Note 2)............................................................ 32 95 -------- -------- Total other obligations.......................................................... 32 39,249 -------- -------- Net unamortized discount on debt..................................................... (247) (281) -------- -------- Long-term debt due within one year................................................... (65,806) (29,415) -------- -------- Total long-term debt............................................................. 185,499 262,047 -------- -------- TOTAL CAPITALIZATION.................................................................... $467,478 $539,190 ======== ======== * Denotes variable rate issue with December 31, 2002 interest rate shown. The accompanying Notes to Financial Statements are an integral part of these statements.
13 PENNSYLVANIA POWER COMPANY STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated Other Other Comprehensive Number Par Paid-In Comprehensive Retained Income of Shares Value Capital Income (Loss) Earnings ------------- --------- ------- ------- ------------- -------- (Dollars in thousands) Balance, January 1, 2000............. 6,290,000 $188,700 $(310) $ -- $ 11,218 Net income........................ $22,847 22,847 ======= Cash dividends on common stock.... (4,900) Cash dividends on preferred stock. (3,704) - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000........... 6,290,000 188,700 (310) -- 25,461 Net income........................ $41,041 41,041 ======= Cash dividends on common stock.... (27,400) Cash dividends on preferred stock. (3,704) - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001........... 6,290,000 188,700 (310) -- 35,398 Net income........................ $ 47,717 47,717 Minimum liability for unfunded retirement benefits, net of $(7,045,000) of income taxes.................... (9,932) (9,932) -------- Comprehensive income.............. $ 37,785 ======== Cash dividends on preferred stock. (3,699) Cash dividends on common stock.... (28,500) - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002........... 6,290,000 $188,700 $(310) $(9,932) $ 50,916 ==================================================================================================================== STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemption -------------------- -------------------- Number Par Number Par of Shares Value of Shares Value (Dollars in thousands) Balance, January 1, 2000.......... 391,049 $39,105 150,000 $15,000 --------------------------------------------------------------------------------------------- Balance, December 31, 2000........ 391,049 39,105 150,000 15,000 --------------------------------------------------------------------------------------------- Balance, December 31, 2001........ 391,049 39,105 150,000 15,000 Redemptions- 7.625% Series.................. (7,500) (750) --------------------------------------------------------------------------------------------- Balance, December 31, 2002........ 391,049 $39,105 142,500 $14,250 ============================================================================================= The accompanying Notes to Financial Statements are an integral part of these statements.
14 PENNSYLVANIA POWER COMPANY STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income............................................................ $ 47,717 $ 41,041 $ 22,847 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization........................ 56,763 57,087 55,964 Nuclear fuel and lease amortization................................ 19,204 17,323 18,248 Deferred income taxes, net......................................... (5,337) (11,055) (8,620) Investment tax credits, net........................................ (2,595) (2,775) (3,051) Receivables........................................................ (8,434) 8,345 (8,484) Materials and supplies............................................. (4,711) 3,997 2,888 Accounts payable................................................... 6,338 (11,413) 8,335 Other ............................................................. (3,183) (9,265) (9,651) ---------- --------- --------- Net cash provided from operating activities...................... 105,762 93,285 78,476 ---------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt..................................................... 14,500 31,626 -- Redemptions and Repayments- Preferred stock.................................................... (750) -- -- Long-term debt..................................................... (56,837) (51,351) (47,796) Dividend Payments- Common stock....................................................... (28,500) (27,400) (4,900) Preferred stock.................................................... (3,699) (3,704) (3,704) ---------- --------- --------- Net cash provided from (used for) financing activities........... (75,286) (50,829) (56,400) ---------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions.................................................... (46,060) (40,529) (29,856) Loans to associated companies......................................... -- (19,175) (59,421) Loan payment from parent.............................................. 19,120 -- -- Sale of assets to associated companies................................ -- 6,053 67,472 Other ................................................................ (2,381) 7,787 (2,466) ---------- --------- --------- Net cash provided from (used for) investing activities........... (29,321) (45,864) (24,271) ---------- --------- --------- Net increase (decrease) in cash and cash equivalents.................. 1,155 (3,408) (2,195) Cash and cash equivalents at beginning of year........................ 67 3,475 5,670 ---------- --------- --------- Cash and cash equivalents at end of year.............................. $ 1,222 $ 67 $ 3,475 ========== ========= ========= SUPPLEMENTAL CASH FLOWS INFORMATION: Cash paid during the year- Interest (net of amounts capitalized).............................. $ 13,771 $ 19,286 $ 18,804 ========== ========= ========= Income taxes....................................................... $ 60,078 $ 53,527 $ 39,704 ========== ========= ========= The accompanying Notes to Financial Statements are an integral part of these statements. 15
PENNSYLVANIA POWER COMPANY STATEMENTS OF TAXES
For the Years Ended December 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: State gross receipts*................................................ $ 18,516 $ 12,776 $ 14,264 Real and personal property........................................... 3,729 59 4,012 State capital stock.................................................. 1,357 1,081 1,598 Social security and unemployment..................................... 750 201 2,137 Other................................................................ 122 97 65 --------- --------- --------- Total general taxes............................................. $ 24,474 $ 14,214 $ 22,076 ========= ========= ========= PROVISION FOR INCOME TAXES: Currently payable- Federal........................................................... $ 38,972 $ 40,948 $ 26,712 State............................................................. 12,004 12,803 11,080 --------- --------- ---------- 50,976 53,751 37,792 --------- --------- ---------- Deferred, net- Federal........................................................... (4,144) (8,304) (4,273) State............................................................. (1,193) (2,751) (4,347) --------- --------- --------- (5,337) (11,055) (8,620) --------- --------- --------- Investment tax credit amortization................................... (2,595) (2,775) (3,051) --------- --------- --------- Total provision for income taxes................................ $ 43,044 $ 39,921 $ 26,121 ========= ========= ========= INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating expenses................................................... $ 41,733 $ 36,909 $ 24,874 Other income......................................................... 1,311 3,012 1,247 --------- --------- --------- Total provision for income taxes................................ $ 43,044 $ 39,921 $ 26,121 ========= ========= ========= RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes........................ $ 90,761 $ 80,962 $ 48,968 ========= ========= ========= Federal income tax expense at statutory rate......................... $ 31,766 $ 28,337 $ 17,139 Increases (reductions) in taxes resulting from: State income taxes, net of federal income tax benefit............. 7,027 6,534 4,376 Amortization of investment tax credits............................ (2,595) (2,775) (3,051) Amortization of tax regulatory assets............................. 5,967 6,315 6,899 Other, net........................................................ 879 1,510 758 --------- --------- --------- Total provision for income taxes................................ $ 43,044 $ 39,921 $ 26,121 ========= ========= ========= ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Competitive transition charge........................................ $ 56,172 $ 75,686 $ 95,497 Property basis differences........................................... 72,488 65,534 64,348 Allowance for equity funds used during construction.................. 1,045 2,608 4,163 Customer receivables for future income taxes......................... 4,249 5,640 7,016 Unamortized investment tax credits................................... (1,578) (1,702) (1,823) Deferred gain for asset sale to affiliated company................... 8,810 9,943 8,925 Other comprehensive income........................................... (7,045) -- -- Other ............................................................... (16,756) (20,901) (17,494) --------- --------- --------- Net deferred income tax liability............................... $ 117,385 $ 136,808 $ 160,632 ========= ========= ========= * Collected from customers through regulated rates and included in revenue on the Statements of Income. The accompanying Notes to Financial Statements are an integral part of these statements. 16
NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Pennsylvania Power Company (Company), a wholly owned subsidiary of Ohio Edison Company (OE), follows the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. (A) REVENUES- The Company's principal business is providing electric service to customers in western Pennsylvania. The Company's retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service through the end of the year. Receivables from customers include sales to residential, commercial and industrial customers located in the Company's service area and sales to wholesale customers. There was no material concentration of receivables at December 31, 2002 or 2001, with respect to any particular segment of the Company's customers. (B) REGULATORY PLAN- Pennsylvania enacted its electric utility competition law in 1996 with the phase in of customer choice for electric generation suppliers completed on January 1, 2001. The Company continues to deliver power to homes and businesses through its distribution system, which remains regulated by the PPUC. The Company's rates have been restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of the Company's rates is excluded from their bill and the customers receive a generation charge from the alternative supplier. The stranded cost recovery portion of rates provides for recovery of certain amounts not otherwise considered recoverable in a competitive generation market, including regulatory assets. In 1998, the PPUC authorized the Company's rate restructuring plan, which essentially resulted in the deregulation of the Company's generation business. The Company was required to remove from its balance sheet all regulatory assets and liabilities related to its generation business and assess all other assets for impairment. The SEC issued interpretive guidance regarding asset impairment measurement concluding that any supplemental regulated cash flows such as a competitive transition charge (CTC) should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance, the Company reduced its nuclear generating unit investments by approximately $305 million, of which approximately $227 million was recognized as a regulatory asset to be recovered through the CTC over a seven-year transition period; the remaining net amount of $78 million was written off. The Company is entitled to recover $236 million of stranded costs through the CTC that began in 1999 and ends in 2006. The Company's net assets included in utility plant relating to the operations for which the application of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) was discontinued were $82 million as of December 31, 2002. (C) UTILITY PLANT AND DEPRECIATION- Utility plant reflects the original cost of construction (except for nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for electric plant was approximately 2.9% in 2002 and 2001 and 2.6% in 2000. Annual depreciation expense includes approximately $1.6 million for future decommissioning costs applicable to the Company's ownership interest in three nuclear generating units (Beaver Valley Units 1 and 2 and Perry Unit 1). The Company's share of the future obligation to decommission these units is approximately $354 million in current dollars and (using a 4.0% escalation rate) approximately $695 million in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Payments for decommissioning are expected to begin in 2016, when actual decommissioning work begins. The Company has recovered approximately $17 million for decommissioning through its electric rates from customers through December 31, 2002. The Company has also 17 recognized an estimated liability of approximately $5.3 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy, as required by the Energy Policy Act of 1992. In June 2001, the Financial Accounting Standards Board issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. The Company has identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $78 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $9 million. Due to the increased carrying amount, the related long-lived assets were tested for impairment in accordance with SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets". No impairment was indicated. The asset retirement liability at the date of adoption will be $121 million. As of December 31, 2002, the Company had recorded decommissioning liabilities of $120 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that the ultimate nuclear decommissioning costs for the Company will be recovered through its regulated rates. Therefore, the Company recognized a regulatory liability of $69 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning for the Company. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $1.1 million decrease to income ($0.6 million net of tax). (D) COMMON OWNERSHIP OF GENERATING FACILITIES- The Company, together with OE and other affiliated companies, The Cleveland Electric Illuminating Company (CEI) and The Toledo Edison Company (TE), own, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly owned facility in the same proportion as its interest. The Company's portion of operating expenses associated with jointly owned facilities is included in the corresponding operating expenses on the Statements of Income. The amounts reflected on the Balance Sheet under utility plant at December 31, 2002 include the following:
Utility Accumulated Construction Company's Plant in Provision for Work in Ownership Generating Units Service Depreciation Progress Interest - ------------------------------------------------------------------------------------------------------------- (In millions) W. H. Sammis #7....................... $ 64.1 $ 24.4 $ -- 20.80% Bruce Mansfield #1, #2 and #3....................... 185.9 114.8 2.7 16.38% Beaver Valley #1 and #2............... 52.6 13.7 32.9 39.37% Perry #1.............................. 3.7 0.9 1.0 5.24% ------------------------------------------------------------------------------------------------------- Total............................. $306.3 $153.8 $36.6 =============================================================================================================
(E) NUCLEAR FUEL- OES Fuel, Incorporated, a wholly owned subsidiary of OE, had been the sole lessor for the Company's nuclear fuel requirements. The Company and OE replaced that lease arrangement with direct ownership and nuclear fuel financing by the Company and OE. The Company amortizes the cost of nuclear fuel based on the rate of consumption. (F) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 3B). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date resulting in substantially no intrinsic value. 18 If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows: 2002 2001 2000 ---------------------------------------------------------------------------- Valuation assumptions: Expected option term (years)... 8.1 8.3 7.6 Expected volatility............ 23.31% 23.45% 21.77% Expected dividend yield........ 4.36% 5.00% 6.68% Risk-free interest rate........ 4.60% 4.67% 5.28% Fair value per option............ $6.45 $4.97 $2.86 ---------------------------------------------------------------------------- The effects of applying fair value accounting to FirstEnergy's stock options would not be material to the Company's net income. (G) INCOME TAXES- Details of the total provision for income taxes are shown on the Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. The Company is included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Company recognizing any tax losses or credits it contributed to the consolidated return. (H) RETIREMENT BENEFITS- FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all of the Company's full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. On December 31, 2001, the FirstEnergy pension plan was merged with the pension plans of GPU, Inc., which merged with FirstEnergy on November 7, 2001. The Company uses the projected unit credit method for funding purposes and was not required to make pension contributions during the three years ended December 31, 2002. The assets of the FirstEnergy pension plan consist primarily of common stocks, United States government bonds and corporate bonds. The Company provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company pays insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Company. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. As a result of the reduced market value of FirstEnergy's pension plan assets, it was required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits," as of December 31, 2002. FirstEnergy's accumulated benefit obligation of $3.438 billion exceeded the fair value of plan assets ($2.889 billion) resulting in a minimum pension liability of $548.6 million. FirstEnergy eliminated its prepaid pension asset of $286.9 million (Company - $8.8 million) and established a minimum liability of $548.6 million (Company - $11.7 million), recording an intangible asset of $78.5 million (Company - $3.6 million) and reducing OCI by $444.2 million (Company - $9.9 million) (recording a related deferred tax asset of $312.8 million (Company - $7.0 million)). The charge to OCI will reverse in future periods to the extent the fair value of trust assets exceed the accumulated benefit obligation. The amount of pension liability recorded as of December 31, 2002, increased due to the lower discount rate and asset returns assumed as of December 31, 2002. 19 The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Other Pension Benefits Postretirement Benefits ---------------- ----------------------- 2002 2001 2002 2001 -------------------------------------------------------------------------------------------- (In millions) Change in benefit obligation: Benefit obligation as of January 1........ $3,547.9 $1,506.1 $ 1,581.6 $ 752.0 Service cost.............................. 58.8 34.9 28.5 18.3 Interest cost ............................ 249.3 133.3 113.6 64.4 Plan amendments........................... -- 3.6 (121.1) -- Actuarial loss............................ 268.0 123.1 440.4 73.3 Voluntary early retirement program........ -- -- -- 2.3 GPU acquisition........................... (11.8) 1,878.3 110.0 716.9 Benefits paid............................. (245.8) (131.4) (83.0) (45.6) --------------------------------------------------------------------------------------------- Benefit obligation as of December 31...... 3,866.4 3,547.9 2,070.0 1,581.6 --------------------------------------------------------------------------------------------- Change in fair value of plan assets: Fair value of plan assets as of January 1. 3,483.7 1,706.0 535.0 23.0 Actual return on plan assets.............. . (348.9) 8.1 (57.1) 12.7 Company contribution ..................... -- -- 37.9 43.3 GPU acquisition........................... -- 1,901.0 -- 462.0 Benefits paid.............................. (245.8) (131.4) (42.5) (6.0) --------------------------------------------------------------------------------------------- Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0 --------------------------------------------------------------------------------------------- Funded status of plan..................... (977.4) (64.2) (1,596.7) (1,046.6) Unrecognized actuarial loss............... 1,185.8 222.8 751.6 212.8 Unrecognized prior service cost........... 78.5 87.9 (106.8) 17.7 Unrecognized net transition obligation.... -- -- 92.4 101.6 -------------------------------------------------------------------------------------------- Net amount recognized..................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) ============================================================================================= Consolidated Balance Sheets classification: Prepaid (accrued) benefit cost............ $ (548.6) $ 246.5 $ (859.5) $ (714.5) Intangible asset.......................... 78.5 -- -- -- Accumulated other comprehensive loss...... 757.0 -- -- -- -------------------------------------------------------------------------------------------- Net amount recognized..................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) ============================================================================================= Company's share of net amount recognized.. $ 8.8 $ 18.1 $ (26.4) $ (37.4) ============================================================================================= Assumptions used as of December 31: Discount rate............................. 6.75% 7.25% 6.75% 7.25% Expected long-term return on plan assets.. 9.00% 10.25% 9.00% 10.25% Rate of compensation increase............. 3.50% 4.00% 3.50% 4.00% FirstEnergy's net pension and other postretirement benefit costs for the three years ended December 31, 2002 were computed as follows:
Other Pension Benefits Postretirement Benefits ------------------------ ------------------------- 2002 2001 2000 2002 2001 2000 ------------------------------------------------------------------------------------------------------ (In millions) Service cost $ 58.8 $ 34.9 $ 27.4 $ 28.5 $18.3 $11.3 Interest cost 249.3 133.3 104.8 113.6 64.4 45.7 Expected return on plan assets (346.1) (204.8) (181.0) (51.7) (9.9) (0.5) Amortization of transition obligation (asset)-- (2.1) (7.9) 9.2 9.2 9.2 Amortization of prior service cost 9.3 8.8 5.7 3.2 3.2 3.2 Recognized net actuarial loss (gain) -- -- (9.1) 11.2 4.9 -- Voluntary early retirement program -- 6.1 17.2 -- 2.3 -- ------------------------------------------------------------------------------------------------------ Net periodic benefit cost (income) $ (28.7) $ (23.8) $ (42.9) $114.0 $92.4 $68.9 ====================================================================================================== Company's share of net benefit cost..... $ 0.4 $ (0.7) $ (3.6) $ 2.1 $ 4.0 $ 7.5 ------------------------------------------------------------------------------------------------------
The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. 20 (I) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily OE, CEI, TE, American Transmission Systems, Inc. (ATSI), FirstEnergy Solutions Corp. (FES) and FirstEnergy Service Company (FECO). The Ohio transition plan resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. Unregulated operations under FES now operate the generation businesses of the Company, OE, CEI and TE. As a result, the Company entered into power supply agreements (PSA) whereby FES purchases all of the Company's nuclear generation and the Company purchases its power from FES to meet its "provider of last resort" obligations. The reduction in revenues for Bruce Mansfield administrative and general charges and costs for FirstEnergy support services in 2001 and 2002 from 2000 levels reflects the transfer of fossil generation operations to FES. In 2002, the Company and OE terminated their nuclear fuel leasing arrangement with OES Fuel and now own their nuclear fuel. The primary affiliated companies transactions, including the effects of the PSA beginning in 2001, the sale and leaseback of the Company's transmission assets to ATSI in September 2000 and FirstEnergy's providing support services at cost, are as follows: 2002 2001 2000 - ------------------------------------------------------------------------------- (In millions) Operating Revenues: PSA revenues with FES..................... $138.0 $151.5 $ -- Generating units rent with FES............ 20.2 20.2 -- Electric sales to affiliated utilitie -- -- 57.6 Bruce Mansfield administrative and general charges........................ -- -- 2.9 Ground lease with ATSI.................... 1.3 1.3 0.7 Operating Expenses: Nuclear fuel leased from OES Fuel......... 4.8 18.7 20.3 Purchased power from affiliated utilities. -- -- 7.1 Purchased power under PSA................. 157.0 152.7 -- Transmission facilities rentals (including ATSI rents)................. 13.3 9.9 5.7 Nuclear operations administrative and generation charges..................... 20.2 18.6 15.0 FirstEnergy support services.............. 8.5 10.1 27.4 Other Income: Interest income from ATSI.................. 2.6 2.6 0.9 Interest income from FES................... 0.5 0.5 -- - ------------------------------------------------------------------------------- FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from its affiliates, GPU Service, Inc. and FECO, both subsidiaries of FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act (PUHCA). The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas; the ratio of each company's amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers and other factors; and specific departmental charge ratios. Management believes that these allocation methods are reasonable. (J) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Balance Sheets at cost, which approximates their fair market value. Noncash financing and investing activities included capital lease transactions amounting to $1.5 million, $21.6 million and $21.2 million for the years 2002, 2001 and 2000, respectively. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31: 21 2002 2001 - -------------------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value -------- ----- -------- ----- (In millions) Long-term debt.............................. $252 $260 $252 $262 Preferred stock............................. 14 14 15 15 Investments other than cash and cash equivalents.......................... 161 165 160 162 - -------------------------------------------------------------------------------- The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to the Company's ratings. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents consist primarily of decommissioning trust investments. The Company has no securities held for trading purposes. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of the Company, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "Investments other than cash and cash equivalents" in the table above) consist of equity securities, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. In conjunction with the adoption of SFAS 143 on January 1, 2003, unrealized gains or losses were reclassified to OCI in accordance with SFAS 115. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized gains (losses) were approximately $(0.3) million and interest and dividend income totaled approximately $5.2 million. (K) REGULATORY ASSETS- The Company recognizes, as regulatory assets, costs which the FERC and PPUC have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Company's rate restructuring plan. Based on the rate restructuring plan, the Company continues to bill and collect cost-based rates relating to the Company's nongeneration operations and continues the application of SFAS 71 to these operations. Net regulatory assets on the Balance Sheets are comprised of the following: 2002 2001 - ----------------------------------------------------------------------------- (In millions) Competitive transition charge.................. $135.7 $182.7 Customer receivables for future income taxes... 10.3 13.6 Loss on reacquired debt........................ 6.9 6.9 Employee postretirement benefit costs.......... 2.8 3.6 Other.......................................... 1.2 2.0 - ----------------------------------------------------------------------------- Total..................................... $156.9 $208.8 ============================================================================= 2. LEASES The Company leases office space and other property and equipment under cancelable and noncancelable leases. Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Statements of Income. Such costs for the three years ended December 31, 2002, are summarized as follows: 2002 2001 2000 ---------------------------------------------------------------------------- (In millions) Operating leases Interest element................... $0.1 $-- $0.3 Other.............................. 0.2 0.1 0.8 Capital leases Interest element................... -- -- 0.4 Other.............................. 0.1 0.1 0.3 ---------------------------------------------------------------------------- Total rentals......................... $ 0.4 $ 0.2 $1.8 ============================================================================ 22 The future minimum lease payments as of December 31, 2002, are: Capital Operating Leases Leases ---------------------------------------------------------------------- (In millions) 2003................................... $0.1 $0.1 2004................................... -- 0.1 2005................................... -- 0.1 2006................................... -- 0.1 2007................................... -- 0.1 Years thereafter....................... -- 0.7 ------------------------------------------------------------------ Total minimum lease payments........... 0.1 $1.2 ==== Executory costs........................ 0.1 ------------------------------------------------ Net minimum lease payments............. -- Interest portion....................... -- ------------------------------------------------ Present value of net minimum lease payments....................... -- Less current portion................... -- ------------------------------------------------ Noncurrent portion..................... $-- ================================================ 3. CAPITALIZATION (A) RETAINED EARNINGS- Under the Company's Charter, the Company's retained earnings unrestricted for payment of cash dividends on the Company's common stock were $41.0 million as of December 31, 2002. (B) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 2002 2001 2000 ----------------------------------------------------------------------- Restricted common shares granted 36,922 133,162 208,400 Weighted average market price $36.04 $35.68 $26.63 Weighted average vesting period (years) 3.2 3.7 3.8 Dividends restricted Yes * Yes * FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2002, there were 296,008 stock units outstanding. 23 Stock option activities under the FE Programs for the past three years were as follows: Number of Weighted Average Stock Option Activities Options Exercise Price -------------------------------------------------------------------- Balance, January 1, 2002 2,153,369 $25.32 (159,755 options exercisable) 24.87 Options granted 3,011,584 23.24 Options exercised 90,491 26.00 Options forfeited 52,600 22.20 Balance, December 31, 2000 5,021,862 24.09 (473,314 options exercisable) 24.11 Options granted 4,240,273 28.11 Options exercised 694,403 24.24 Options forfeited 120,044 28.07 Balance, December 31, 2001 8,447,688 26.04 (1,828,341 options exercisable) 24.83 Options granted 3,399,579 34.48 Options exercised 1,018,852 23.56 Options forfeited 392,929 28.19 Balance, December 31, 2002 10,435,486 28.95 (1,400,206 options exercisable) 26.07 As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 1F - "Stock-Based Compensation." (C) PREFERRED STOCK- The Company's 7.75% series of preferred stock has a restriction which prevents early redemption prior to July 2003. All other preferred stock may be redeemed by the Company in whole, or in part, with 30-60 days' notice. (D) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- The Company's 7.625% series has an annual sinking fund requirement for 7,500 shares. (E) LONG-TERM DEBT- The Company has a first mortgage indenture under which it issues from time to time first mortgage bonds secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Company. Based on the amount of bonds authenticated by the mortgage bond trustee through December 31, 2002, the Company's annual improvement fund requirements for all bonds issued under its first mortgage indenture amounts to $9.2 million. The Company expects to deposit funds with its mortgage bond trustee in 2003 that will then be withdrawn upon the surrender for cancellation of a like principal amount of bonds, which are specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) during the next five years are $65.8 million in 2003, $40.7 million in 2004 and $1.0 million in each year 2005 through 2007. Included in these amounts are various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. Those amounts are $25 million and $5 million in 2003 and 2004, respectively, which is the next time debt holders may exercise this provision. 24 The Company's obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $10.4 million and noncancelable municipal bond insurance policies of $32.9 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letters of credit or policies, the Company is entitled to a credit against its obligation to repay the related bond. The Company pays an annual fee of 1.375% of the amount of the letters of credit to the issuing bank and is obligated to reimburse the bank for any drawings thereunder. (F) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with OE. As of December 31, 2002, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $9.9 million. 4. SHORT-TERM BORROWINGS: The Company may borrow from affiliates on a short-term basis. As of December 31, 2002, the Company had no short-term borrowings. 5. COMMITMENTS AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $123 million for property additions and improvements from 2003-2007, of which approximately $53 million is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $42 million, of which approximately $19 million applies to 2003. During the same periods, the Company's nuclear fuel investments are expected to be reduced by approximately $34 million and $17 million, respectively, as the nuclear fuel is consumed. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its ownership interests in the Beaver Valley Station and the Perry Plant, the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $74.0 million per incident but not more than $8.4 million in any one year for each incident. The Company is also insured as to its interest in Beaver Valley and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $222.1 million of insurance coverage for replacement power costs for its interests in Beaver Valley and Perry. Under these policies, the Company can be assessed a maximum of approximately $13.1 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Company's plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs. (C) ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. Generation operations and any related additional capital expenditures for environmental compliance are the responsibility of FirstEnergy's competitive services business unit. The Company is required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Company cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. 25 The Company believes it is in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Company's 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 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 Company's Pennsylvania facilities by May 1, 2003. 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 Company operates affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against the Company and OE in the U.S. District Court for the Southern District of Ohio, for which hearings began 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 require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of these proceedings, the Company and OE believe the Sammis Plant is in full compliance with the Clean Air Act and the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. 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 effects of compliance on the Company with regard to environmental matters could have a material adverse effect on the Company's earnings and competitive position. These environmental regulations affect the Company's earnings and competitive position to the extent 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. The Company 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. (D) LEGAL MATTERS- Various lawsuits, claims and proceedings related to the Company's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant applicable to the Company are described above. 6. RECENTLY ISSUED ACCOUNTING STANDARDS FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair 26 value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Company does not believe that implementation of FIN 45 will be material but it will continue to evaluate anticipated guarantees. 7. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain operating results by quarter for 2002 and 2001.
March 31, June 30, September 30, December 31, Three Months Ended 2002 2002 2002 2002 - --------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues........................ $ 124.3 $ 127.8 $ 131.9 $ 122.4 Operating Expenses and Taxes.............. 109.2 106.3 113.1 116.9 - --------------------------------------------------------------------------------------------------------------- Operating Income.......................... 15.1 21.5 18.8 5.5 Other Income.............................. 0.7 0.5 0.7 0.1 Net Interest Charges...................... 3.8 4.0 3.7 3.6 - --------------------------------------------------------------------------------------------------------------- Net Income................................ $ 12.0 $ 18.0 $ 15.8 $ 2.0 =============================================================================================================== Earnings on Common Stock.................. $ 11.0 $ 17.1 $ 14.9 $ 1.0 =============================================================================================================== March 31, June 30, September 30, December 31, Three Months Ended 2001 2001 2001 2001 - --------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues........................ $ 128.4 $ 124.7 $ 121.3 $ 124.0 Operating Expenses and Taxes.............. 112.4 101.8 118.7 110.3 - --------------------------------------------------------------------------------------------------------------- Operating Income.......................... 16.0 22.9 2.6 13.7 Other Income.............................. 0.9 0.7 1.0 0.6 Net Interest Charges...................... 4.5 4.6 4.3 4.0 - --------------------------------------------------------------------------------------------------------------- Net Income (Loss)......................... $ 12.4 $ 19.0 $ (0.7) $ 10.3 =============================================================================================================== Earnings (Loss) Applicable to Common Stock $ 11.5 $ 18.1 $ (1.7) $ 9.4 ===============================================================================================================
27 Report of Independent Accountants To the Stockholders and Board of Directors of Pennsylvania Power Company: In our opinion, the accompanying balance sheet and statement of capitalization and the related statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of Pennsylvania Power Company (a wholly owned subsidiary of Ohio Edison Company) as of December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The financial statements of Pennsylvania Power Company as of December 31, 2001 and for each of the two years in the period ended December 31, 2001 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financials statements in their report dated March 18, 2002. PricewaterhouseCoopers LLP Cleveland, Ohio February 28, 2003 28 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. Report of Independent Public Accountants To the Stockholders and Board of Directors of Pennsylvania Power Company: We have audited the accompanying balance sheets and statements of capitalization of Pennsylvania Power Company (a Pennsylvania corporation and wholly owned subsidiary of Ohio Edison Company) as of December 31, 2001 and 2000, and the related statements of income, common stockholder's equity, preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Pennsylvania Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. 29 ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. EX-23 29 pp_ex23-2.txt EX. 23-2 PWC CONSENT - PENN EXHIBIT 23.2 PENNSYLVANIA POWER COMPANY CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 33-62450 and 33-65156) of Pennsylvania Power Company of our report dated February 28, 2003 relating to the financial statements, which appears in the Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 28, 2003 relating to the financial statement schedule, which appears in this Form 10-K. PricewaterhouseCoopers LLP Cleveland, Ohio March 24, 2003 EX-12 30 jc_ex12-6.txt EX. 12-6 FIXED CHARGE RATIO - JCP&L EXHIBIT 12.6 Page 1 JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
Year Ended December 31, ------------------------------- Jan. 1- Nov. 7 Year Ended 1998 1999 2000 Nov. 6, 2001 Dec. 31, 2001 Dec. 31, 2002 --------- --------- -------- ------------ ------------- ------------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items..................... $222,442 $172,380 $210,812 $ 34,467 | $30,041 $251,895 Interest and other charges, before reduction for | amounts capitalized................................. 110,190 106,675 105,799 95,727 | 16,919 100,365 Provision for income taxes............................ 145,078 100,970 119,875 52 | 20,101 181,855 Interest element of rentals charged to income (a)..... 11,838 14,920 6,229 3,913 | 124 3,239 -------- -------- -------- -------- | ------- -------- Earnings as defined................................. $489,548 $394,945 $442,715 $134,159 | $67,185 $537,354 ======== ======== ======== ======== | ======= ======== | FIXED CHARGES AS DEFINED IN REGULATION S-K: | Interest on long-term debt............................ $ 87,261 $ 87,196 $ 85,220 $ 77,205 | $14,234 $ 92,314 Other interest expense................................ 12,229 8,779 9,879 9,427 | 1,080 (2,643) Subsidiary's preferred stock dividend requirements.... 10,700 10,700 10,700 9,095 | 1,605 10,694 Interest element of rentals charged to income (a)..... 11,838 14,920 6,229 3,913 | 124 3,239 -------- -------- -------- -------- | ------- -------- Fixed charges as defined............................ $122,028 $121,595 $112,028 $ 99,640 | $17,043 $103,604 ======== ======== ======== ======== | ======= ======== | CONSOLIDATED RATIO OF EARNINGS TO FIXED | CHARGES............................................... 4.01 3.25 3.95 1.35 | 3.94 5.19 ==== ==== ==== ==== | ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
EXHIBIT 12.6 Page 2 JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
Year Ended December 31, ---------------------------- Jan. 1- Nov. 7 Year Ended 1998 1999 2000 Nov. 6, 2001 Dec. 31, 2001 Dec. 31, 2002 --------- -------- ------- ------------ ------------- ------------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items................... $222,442 $172,380 $210,812 $ 34,467 | $30,041 $251,895 Interest and other charges, before reduction for | amounts capitalized............................... 110,190 106,675 105,799 95,727 | 16,919 100,365 Provision for income taxes.......................... 145,078 100,970 119,875 52 | 20,101 181,855 Interest element of rentals charged to income (a)... 11,838 14,920 6,229 3,913 | 124 3,239 -------- -------- -------- -------- | ------- -------- Earnings as defined............................... $489,548 $394,945 $442,715 $134,159 | $67,185 $537,354 ======== ======== ======== ======== | ======= ======== | FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS | PREFERRED STOCK DIVIDEND REQUIREMENTS | (PRE-INCOME TAX BASIS): | Interest on long-term debt.......................... $ 87,261 $ 87,196 $ 85,220 $ 77,205 | $14,234 $ 92,314 Other interest expense.............................. 12,229 8,779 9,879 9,427 | 1,080 (2,643) Preferred stock dividend requirements............... 20,765 19,370 17,604 13,642 | 2,303 9,230 Adjustments to preferred stock dividends to | state on a pre-income tax basis................... 6,562 5,081 3,928 7 | 467 (1,057) Interest element of rentals charged to income (a)... 11,838 14,920 6,229 3,913 | 124 3,239 -------- -------- -------- -------- | ------- -------- Fixed charges as defined plus preferred stock | dividend requirements (pre-income tax basis).... $138,655 $135,346 $122,860 $104,194 | $18,208 $101,083 ======== ======== ======== ======== | ======= ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES | PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS | (PRE-INCOME TAX BASIS).............................. 3.53 2.92 3.60 1.29 | 3.69 5.32 ==== ==== ==== ==== | ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
EX-13 31 jc_ex13-5.txt EX. 13-5 ANNUAL REPORT - JCP&L EXHIBIT 13.5 JERSEY CENTRAL POWER & LIGHT COMPANY 2002 ANNUAL REPORT TO STOCKHOLDERS Jersey Central Power & Light Company (JCP&L) is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the distribution and sale of electric energy in an area of approximately 3,300 square miles in New Jersey. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 2.7 million. In August 2000, FirstEnergy entered into an agreement to merge with GPU, Inc., under which FirstEnergy would acquire all of the outstanding shares of GPU, Inc.'s common stock for approximately $4.5 billion in cash and FirstEnergy common stock. The merger became effective on November 7, 2001 and is being accounted for by the purchase method. Prior to that time, Jersey Central Power & Light Company was a wholly owned subsidiary of GPU, Inc. Contents Page - -------- ---- Selected Financial Data........................................... 1 Management's Discussion and Analysis.............................. 2-11 Consolidated Statements of Income................................. 12 Consolidated Balance Sheets....................................... 13 Consolidated Statements of Capitalization......................... 14 Consolidated Statements of Common Stockholder's Equity............ 15 Consolidated Statements of Preferred Stock........................ 15 Consolidated Statements of Cash Flows............................. 16 Consolidated Statements of Taxes.................................. 17 Notes to Consolidated Financial Statements........................ 18-30 Reports of Independent Accountants................................ 31-32 JERSEY CENTRAL POWER & LIGHT COMPANY SELECTED FINANCIAL DATA
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 1999 1998 - ---------------------------------------------------------------------------------------------------------------------- (Dollars in thousands) Operating Revenues...................... $2,328,415 $ 282,902 | $1,838,638 $1,979,297 $2,018,209 $2,069,648 ========== ========== | ========== ========== ========== ========== | Operating Income........................ $ 335,209 $ 43,666 | $ 292,847 $ 283,227 $ 277,420 $ 297,614 ========== ========== | ========== ========== ========== ========== | Net Income ............................. $ 251,895 $ 30,041 | $ 34,467 $ 210,812 $ 172,380 $ 222,442 ========== ========== | ========== ========== ========== ========== | Earnings on Common Stock................ $ 253,359 $ 29,343 | $ 29,920 $ 203,908 $ 162,862 $ 212,377 ========== ========== | ========== ========== ========== ========== | Total Assets............................ $8,052,755 $8,039,998 | $6,009,054 $5,587,677 $4,382,073 ========== ========== | ========== ========== ========== | | Capitalization: | Common Stockholder's Equity.......... $3,274,069 $3,163,701 | $1,459,260 $1,385,367 $1,557,073 Preferred Stock- | Not Subject to Mandatory Redemption 12,649 12,649 | 12,649 12,649 37,741 Subject to Mandatory Redemption.... -- 44,868 | 51,500 73,167 86,500 Company-Obligated Mandatorily | Redeemable Preferred Securities.... 125,244 125,250 | 125,000 125,000 125,000 Long-Term Debt....................... 1,210,446 1,224,001 | 1,093,987 1,133,760 1,173,532 ---------- ---------- | ---------- ---------- ---------- Total Capitalization............... $4,622,408 $4,570,469 | $2,742,396 $2,729,943 $2,979,846 ========== ========== | ========== ========== ========== | | Capitalization Ratios: | Common Stockholder's Equity.......... 70.8% 69.2%| 53.2% 50.7% 52.2% Preferred Stock- | Not Subject to Mandatory Redemption 0.3 0.3 | 0.5 0.5 1.3 Subject to Mandatory Redemption.... -- 1.0 | 1.9 2.7 2.9 Company-Obligated Mandatorily | Redeemable Preferred Securities.... 2.7 2.7 | 4.5 4.6 4.2 Long-Term Debt....................... 26.2 26.8 | 39.9 41.5 39.4 ----- ----- | ----- ----- ----- Total Capitalization............... 100.0% 100.0%| 100.0% 100.0% 100.0% ===== ===== | ===== ===== ===== | | Transmission and Distribution | Kilowatt-Hour Deliveries (Millions): | Residential.......................... 8,976 1,428 | 7,042 8,087 7,978 7,551 Commercial........................... 8,509 1,330 | 6,787 7,706 7,624 7,259 Industrial........................... 3,171 474 | 2,670 3,307 3,289 3,474 Other................................ 81 17 | 66 82 81 81 ------ ------- | ------ ------ ------ ------ Total Retail......................... 20,737 3,249 | 16,565 19,182 18,972 18,365 Total Wholesale...................... 5,039 295 | 1,780 2,161 1,622 1,690 ------ ------- | ------ ------ ------ ------ Total................................ 25,776 3,544 | 18,345 21,343 20,594 20,055 ====== ======= | ====== ====== ====== ====== | | Customers Served: | Residential.......................... 921,716 909,494 | 896,629 883,930 872,134 Commercial........................... 112,385 109,985 | 107,479 107,210 105,611 Industrial........................... 2,759 2,785 | 2,835 2,965 3,014 Other................................ 1,393 1,484 | 1,551 1,648 1,635 --------- --------- | --------- ------- ------- Total................................ 1,038,253 1,023,748 | 1,008,494 995,753 982,394 ========= ========= | ========= ======= ======= 1
JERSEY CENTRAL POWER & LIGHT COMPANY Management's Discussion and Analysis of Results of Operations and Financial Condition This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Results of Operations In 2002, earnings on common stock increased to $253.4 million, from $59.3 million in 2001, due to higher operating revenues and the absence of a 2001 after-tax charge of $177.5 million, which reduced deferred costs in accordance with the Stipulation of Settlement related to the merger of FirstEnergy and GPU, Inc. Partially offsetting these favorable results were increased purchased power costs. In 2001, earnings on common stock decreased by 70.9% to $59.3 million, from $203.9 million in 2000. Results in 2001 were negatively impacted by the $177.5 after-tax charge previously discussed, and by higher purchased power costs. Partially offsetting these factors were lower other operating costs, and the absence of nuclear operating costs in 2001, as well as increases in operating revenues. Operating revenues increased $206.9 million in 2002, following a $142.2 million increase in 2001. The sources of the changes in operating revenues during 2002 and 2001, as compared to the prior year, are summarized in the following table. Sources of Revenue Changes 2002 2001 ------------------------------------------------------------------------- Increase (Decrease) (In millions) Increase in kilowatt-hour sales due to level of retail-customers shopping for generation service... $ 34.4 $ 67.3 Increase in other retail kilowatt-hour sales......... 98.2 38.4 Increase in wholesale sales.......................... 74.1 44.1 All other changes.................................... 0.2 (7.6) ------------------------------------------------------------------------- Net Increase in Operating Revenues................... $206.9 $142.2 ========================================================================= Electric Sales In 2002, further reductions in the number of customers who received their power from alternate suppliers, and therefore returned to us as full service customers, continued to have a positive effect on operating revenues. During 2002, only 0.7% of kilowatt-hours delivered were to shopping customers, whereas that percentage was 4.5% in 2001 and 11.7% in 2000. In addition to the higher revenues from returning shopping customers, warmer summer weather in both 2002 and 2001 contributed to significant increases in retail sales. This was partially offset by a decrease in kilowatt-hour sales to industrial customers, due to a decline in economic conditions during 2002. On August 1, 2002, the obligation to provide power to customers not choosing to receive power from an alternative energy supplier, referred to as Basic Generation Service (BGS), was transferred from us to external parties through an auction process authorized by the New Jersey Board of Public Utilities (NJBPU). Therefore, we began selling all of our self-supplied energy (non-utility generation and owned generation) into the wholesale market. This contributed to a significant increase in kilowatt-hour sales to wholesale customers during 2002; however, that increase was partially offset by lower average prices for energy in 2002, compared to 2001. Less kilowatt-hour sales were sold to wholesale customers in 2001; however, revenues increased due to higher average prices for energy sold compared to 2000 prices. 2 Changes in kilowatt-hour sales by customer class in 2002 and 2001 are summarized in the following table: Changes in Kilowatt-hour Sales 2002 2001 -------------------------------------------------- Increase (Decrease) Residential.................. 7.0% 4.7% Commercial................... 3.4% 5.3% Industrial................... (0.7)% (4.9)% -------------------------------------------------- Total Retail................. 4.3% 3.3% Wholesale.................... 142.8% (4.0)% -------------------------------------------------- Total Sales.................. 17.4% 2.6% -------------------------------------------------- Operating Expenses and Taxes Total operating expenses and taxes increased $208.2 million in 2002, after increasing $89.0 million in 2001, compared to the preceding year. In both periods, higher purchased power costs accounted for the majority of the increase. In 2002, the increase was offset in part by lower general taxes, due principally to a reduction in the New Jersey transitional energy facilities assessment during the second quarter of 2002. In 2001, the increase in purchased power costs was partially offset by lower other operating costs, due to reduced bad debt expense and employee benefit costs, and decreased nuclear operating costs. With the sale of the Oyster Creek Nuclear Generating Station in August 2000, we no longer have any nuclear operating costs, which were $78.5 million in 2000. However, as a result of the sale and higher customer demand in 2002 and 2001, we have been required to purchase more power. In 2002, fuel and purchased power costs increased $179.6 million, compared to 2001. The increase was due primarily to more power being purchased through two-party agreements and from associated companies during 2002. The increase was partially offset by a decrease in power purchased through the PJM Power Pool, and the absence of non-utility generation contract buyout costs recognized in 2001. Fuel and purchased power costs increased $177.6 million in 2001, compared to 2000. That increase was primarily attributed to greater quantities of power purchased through both two-party agreements and through the PJM Power Pool. Also contributing to the increase was a higher average cost of two-party power purchases in 2001 than in 2000. These increases were partially offset by lower fuel costs due to the sale of Oyster Creek. Other Income Other income increased $183.3 million in 2002, after decreasing $199.8 million in 2001, compared to the prior year. The change in both periods was due primarily to a 2001 charge of $300 million ($177.5 million net of tax) to reduce deferred costs in accordance with the Stipulation of Settlement related to the merger between FirstEnergy and GPU. Net Interest Charges In 2002, net interest charges decreased $5.3 million, compared to 2001, due primarily to reduced short-term borrowing levels and the amortization of fair value adjustments recognized in connection with the merger. These reductions were partially offset by a decrease in deferred interest costs. In addition, we issued $320 million of transition bonds through a special purpose finance subsidiary in 2002 (see Note 4F) and $150 million of notes in 2001, and redeemed $192 million of notes in 2002 and $40 million of notes in 2001. These transactions collectively had a minimal net effect on interest charges in 2002. In 2001, net interest charges decreased $0.2 million, compared to the prior year, with the slight decrease due to an increase in deferred interest costs, offset by interest expense on the senior notes issued in 2001 and higher average short-term debt levels. Preferred Stock Dividend Requirements In the third quarter of 2002, we realized a $3.6 million non-cash gain on the reacquisition of $29.8 million of preferred stock. Preferred stock dividend requirements decreased $3.1 million in 2002, and $1.7 million in 2001, compared to the prior year, due to the 2002 reacquisition and redemptions of cumulative preferred stock pursuant to mandatory and optional sinking fund provisions during 2002 and 2001. 3 Capital Resources and Liquidity Changes in Cash Position As of December 31, 2002, we had $4.8 million of cash and cash equivalents compared with $31.4 million as of December 31, 2001. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash flows provided from operating activities totaled $309.0 million in 2002 and $289.8 million in 2001. The sources of these changes are as follows: Operating Cash Flows 2002 2001 ---------------------------------------------------------- (in millions) Cash earnings (1).................. $325 $219 Working capital and other.......... (16) 71 ---------------------------------------------------------- Total..................... $309 $290 ========================================================== (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, and and investment tax credits. Cash Flows From Financing Activities In 2002, net cash used for financing activities of $140.4 million reflects redemptions of debt and preferred stock, as well as $190.7 million in common dividend payments to FirstEnergy, offset in part by proceeds from the issuance of transition bonds. The following table provides details regarding new issues and redemptions during 2002: Securities Issued or Redeemed in 2002 ------------------------------------------------------------- (in millions) New Issues Transition Bonds (See Note 4)............... $320 ------------------------------------------------------------- Redemptions First Mortgage Bonds........................ 192 Preferred Stock............................. 52 Other....................................... 4 ------------------------------------------------------------- Total Redemptions....................... 248 Short-term Borrowings, net use of cash........... 18 ------------------------------------------------------------- We had no short-term indebtedness on December 31, 2002, compared to $18.1 million on December 31, 2001. We may borrow from our affiliates on a short-term basis. We will not issue first mortgage bonds (FMBs) other than as collateral for senior notes, since our senior note indentures prohibit (subject to certain exceptions) us from issuing any debt which is senior to the senior notes. As of December 31, 2002, we had the capability to issue $393 million of additional senior notes based upon FMB collateral. At year-end 2002, based upon applicable earnings coverage tests and our charter, we could issue $1.2 billion of preferred stock (assuming no additional debt was issued). At the end of 2002, our common equity as a percentage of capitalization stood at 71%, as compared to 69% and 53% at the end of 2001 and 2000, respectively. In 2001, we experienced a significant increase in this ratio due to the allocation of the purchase price when we were acquired by FirstEnergy. Cash Flows From Investing Activities In 2002, cash used in investing activities totaled $195.2 million, principally for property additions to support the distribution of electricity and loans to associated companies. In 2001, $167.0 million of cash was used in investing activities, principally for property additions. Our cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Over the next three years, we expect to meet our contractual obligations with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets. 4 Less than 1-3 3-5 More than Contractual Obligations Total 1 Year Years Years 5 Years - ------------------------------------------------------------------------------ (in millions) Long-term debt......... $1,374 $174 $ 243 $ 267 $ 690 Preferred stock (1).... 125 -- -- -- 125 Operating leases....... 66 3 3 3 57 Purchases (2).......... 4,159 528 943 953 1,735 - --------------------------------------------------------------------------- Total............... $5,724 $705 $1,189 $1,223 $2,607 - --------------------------------------------------------------------------- (1) Subject to mandatory redemption (2) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing Our capital spending for the period 2003 through 2007 is expected to be about $462 million, of which approximately $102 million applies to 2003. Following approval of the merger of FirstEnergy and GPU by the NJBPU on September 26, 2001, Standard and Poor's adjusted our corporate credit rating from A/A1 to BBB/A-2, our senior secured debt rating from A+ to BBB+ and our preferred stock rating from BBB+ to BB+. The credit rating outlook of both Standard & Poor's and Moody's is stable. On February 22, 2002, Moody's Investor Service changed its credit rating outlook for FirstEnergy from stable to negative. The change was based upon a decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania Public Utility Commission (PPUC) for reconsideration of its decision on the mechanism for sharing merger savings and reversed the PPUC decisions regarding rate relief and accounting deferrals rendered in connection with its approval of the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed its outlook for FirstEnergy's credit ratings from stable to negative citing recent developments including: damage to the Davis-Besse reactor vessel head (we have no ownership interest in Davis-Besse), the Pennsylvania Commonwealth Court decision, and deteriorating market conditions for some sales of FirstEnergy's remaining non-core assets. On July 31, 2002, Fitch revised its rating outlook for FirstEnergy securities to negative from stable. The revised outlook reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's judgment about NRG's financial ability to consummate the purchase of four power plants from FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while NRG's liquidity position added uncertainty to FirstEnergy's sale of power plants to NRG, FirstEnergy's ratings would not be affected. S&P found its cash flows sufficiently stable to support a continued (although delayed) program of debt and preferred stock redemption. S&P noted that it would continue to closely monitor our progress on various initiatives. On January 21, 2003, S&P indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa (FirstEnergy's Argentina operations), which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining its current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the Jersey Central Power & Light Company rate case, successful hedging of our short power position, and continued capture of projected merger savings. While FirstEnergy anticipates being prepared to restart the Davis-Besse plant in the spring of 2003, the Nuclear Regulatory Commission (NRC) must authorize the unit's restart following a formal inspection process prior to FirstEnergy's returning the unit to service. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt could put additional pressure on JCP&L's credit ratings. Market Risk Information We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. Our Risk Policy Committee, comprised of FirstEnergy executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk We are exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including forward contracts, options and futures contracts. The derivatives are used for hedging purposes. Most of our non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under Statement of Financial Accounting Standards (SFAS) 133. The change in the fair value of commodity derivative contracts related to energy production during 2002 is summarized in the following table: 5 Increase (Decrease) in the Fair Value of Commodity Derivative Contracts
Non-Hedge Hedge Total --------- ----- ----- (In millions) Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2002...................... $ 1.1 $ 0.4 $1.5 New contract value when entered.................................. -- 2.1 2.1 Additions/Change in value of existing contracts.................. 7.6 (2.3) 5.3 Settled contracts................................................ -- (0.3) (0.3) -------------------------- Net Assets - Derivatives Contracts as of December 31, 2002 (1)... $ 8.7 $(0.1) $8.6 ========================== Impact of Changes in Commodity Derivative Contracts (2) Balance Sheet Effects: Other Comprehensive Income (Pre-Tax).......................... $ -- $(2.6) $2.6) Regulatory Liability.......................................... $ 7.6 $ -- $7.6
(1) Includes $8.6 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Represents the increase in value of existing contracts and settled contracts. Non-Hedge Hedge Total --------- ----- ----- (In millions) Current- Other Liabilities............... $ -- $(0.1) $(0.1) Non-Current- Other Deferred Charges.......... 8.7 -- 8.7 ---- ---- ----- Net assets.................... $8.7 $(0.1) $ 8.6 ==== ====== ===== Derivatives included on the Consolidated Balance Sheet as of December 31, 2002: The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. We use these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: Source of Information - Fair Value by Contract Year - --------------------------------------------------- 2003 2004 2005 2006 Thereafter Total ---- ---- ---- ---- ---------- ----- (In millions) Prices based on external sources(1)... $0.2 $0.3 $0.7 $ -- $ -- $1.2 Prices based on models................ -- -- -- 1.1 6.3 7.4 --------------------------------------- Total(2).......................... $0.2 $0.3 $0.7 $1.1 $6.3 $8.6 ======================================= (1) Broker quote sheets. (2) Includes $8.6 million from an embedded option that is offset by a regulatory liability and does not affect earnings. We perform sensitivity analyses to estimate our exposure to the market risk of our commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2002. Interest Rate Risk - ------------------ Our exposure to fluctuations in market interest rates is reduced since our debt has fixed interest rates, as noted in the following table. 6 Comparison of Carrying Value to Fair Value - ----------------------------------------------------------------------------------------------------------------
There- Fair 2003 2004 2005 2006 2007 after Total Value - ---------------------------------------------------------------------------------------------------------------- (Dollars in millions) Assets - ---------------------------------------------------------------------------------------------------------------- Investments other than Cash and Cash Equivalents-Fixed Income.... -- -- -- -- -- $224 $ 224 $ 224 Average interest rate....... 5.0% 5.0% - ---------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------- Liabilities - ---------------------------------------------------------------------------------------------------------------- Long-term Debt: Fixed rate..................... $174 $176 $67 $231 $36 $690 $1,374 $1,415 Average interest rate ...... 6.1% 6.9% 6.1% 6.5% 6.1% 7.0% 6.7% - ---------------------------------------------------------------------------------------------------------------- Preferred Stock................ -- -- -- -- -- $125 $ 125 $ 127 Average dividend rate ...... 8.6% 8.6% - ----------------------------------------------------------------------------------------------------------------
We are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. Changes in the market value of our nuclear decommissioning trust funds are recognized by making corresponding changes to the decommissioning liability, as described in Note 1 to the consolidated financial statements. Equity Price Risk - ----------------- Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $52 million and $65 million at December 31, 2002 and 2001, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of December 31, 2002. (See Note 1 - "Supplemental Cash Flows Information.") Outlook Our industry continues to transition to a more competitive environment. Beginning in late 1999, all of our customers could select alternative energy suppliers. We continue to deliver power to homes and businesses through our existing distribution system, which remains regulated. To support customer choice, rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs (confirmed by a NJBPU Final Decision and Order issued in March 2001). On August 1, 2002, the obligation to provide power to those customers not choosing to receive power from an alternative energy supplier, referred to as BGS, was transferred from us to external parties through an auction process authorized by the NJBPU. Regulatory assets are costs which regulatory agencies have authorized for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of our regulatory assets are expected to continue to be recovered under the provisions of the regulatory plans as discussed below. Our regulatory assets totaled $3.2 billion and $3.3 billion as of December 31, 2002 and 2001, respectively. Regulatory Matters 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, we 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 market transition charge and societal benefits charge rates; one proposed method of recovery of these costs is the securitization of the deferred balance as further discussed below. This securitization methodology is similar to the Oyster Creek securitization discussed below. Hearings began in February 2003. The Administrative Law Judge's recommended decision is due in June 2003 and the NJBPU's subsequent decision is due in July 2003. Our regulatory plan provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. A February 2002 NJBPU order authorized us to issue $320 million of transition bonds to securitize the recovery of these costs and provided for a usage-based non-bypassable transition bond charge and for the transfer of the bondable transition property to another entity. We sold $320 million of transition bonds through a wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 -- that debt is recognized on the Consolidated Balance Sheet (see Note 4). We are permitted to defer for future collection from customers the amounts by which our costs of supplying BGS to non-shopping customers and costs incurred under non-utility generation agreements exceed amounts collected through BGS and market transition charge rates. As of December 31, 2002, the accumulated deferred cost balance totaled approximately $549 million. The NJBPU also allowed securitization of our deferred balance to the extent permitted by law upon our application and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. 7 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 results of the February 2002 auction, with the NJBPU's approval, removed our BGS obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In February 2003, the auctioning of BGS for the period beginning August 1, 2003 took place. 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. We will sell all self-supplied energy (non-utility generation and owned generation) into the wholesale market, which will offset our deferred energy cost balance. As part of the restructuring orders, we were obligated, through July 31, 2002, to supply electricity to customers who do not choose an alternate supplier. The total forecasted peak of this obligation in 2002 was 5,400 MW. The successful BGS auction in New Jersey removed that BGS obligation for the period from August 1, 2002 to July 31, 2003. FERC Regulatory Matters On December 19, 2002 the Federal Energy Regulatory Commission (FERC) granted unconditional Regional Transmission Organization status to PJM Interconnection, LLC (PJM). We are a transmission owner in PJM. Environmental Matters We have been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, 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, our proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, we have accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered through a non-bypassable societal benefits charge. We have accrued liabilities aggregating approximately $47.1 million as of December 31, 2002. We do not believe environmental remediation costs will have a material adverse effect on our financial condition, cash flows or results of operations. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against us, the most significant of which are described below. We have a 25% ownership interest in Unit 2 of the Three Mile Island Nuclear Plant (TMI-2), which was damaged during a 1979 accident. As a result of the accident, claims for alleged personal injury against us, Metropolitan Edison Company, Pennsylvania Electric Company and GPU (the defendants) had been filed in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by the defendants and dismissed the ten initial "test cases" which had been selected for a test case trial. In January 2002, the District Court granted our motion for summary judgment on the remaining 2,100 pending claims. In February 2002, the plaintiffs filed a notice of appeal of this decision (see Note 6 - Other Legal Proceedings). In December 2002, the Court of Appeals for the Third Circuit refused to hear the appeal which effectively ended further legal action for those claims. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including JCP&L. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, we provided unsafe, inadequate or improper service to our customers. In July 1999, two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court against JCP&L and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in our service territory. In May 2001, the court denied without prejudice our motion seeking decertification of the class. Discovery continues in the class action, but no trial date has been set. In October 2001, the court held argument on the plaintiffs' motion for partial summary judgment, which contends that we are bound to several findings of the NJBPU investigation. The plaintiffs' motion was denied by the Court in November 2001 and the plaintiffs' motion to file an appeal of this decision was denied by the New Jersey Appellate Division. We have also filed a motion for partial summary judgment that is currently pending before the Superior Court. We are unable to predict the outcome of these matters. 8 Significant Accounting Policies We prepare our consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Our more significant accounting policies are described below. Purchase Accounting On November 7, 2001, the merger between FirstEnergy and GPU became effective, and we became a wholly owned subsidiary of FirstEnergy. The merger was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities were based primarily on estimates. The adjustments reflected in our records, which were finalized in the fourth quarter of 2002, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. As of December 31, 2002, we had recorded goodwill of approximately $2.0 billion related to the merger. Regulatory Accounting We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in New Jersey, a significant amount of regulatory assets have been recorded - $3.2 billion as of December 31, 2002. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. We continually monitor our derivative contracts to determine if our activities, expectations, intentions, assumptions and estimates remain valid. As part of our normal operations, we enter into commodity contracts which increase the impact of derivative accounting judgments. Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers 9 Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, we reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. The market values of our pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002, plan assets have earned (11.3)%. Our pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, we will not be required to fund our pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to our 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. Our non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $29 million and $10 million, respectively - a total of $39 million in 2003 as compared to 2002. Increase in Costs from Adverse Changes in Key Assumptions - ----------------------------------------------------------------------------- Assumption Adverse Change Pension OPEB Total - ----------------------------------------------------------------------------- (In millions) Discount rate................ Decrease by 0.25% $2.5 $1.3 $3.8 Long-term return on assets... Decrease by 0.25% $1.7 $0.5 $2.2 Health care trend rate....... Increase by 1% na $3.7 $3.7 Long-Lived Assets In accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment were to occur, other than of a temporary nature, we would recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). 10 Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- SFAS 143, "Accounting for Asset Retirement Obligations" In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize regulatory assets or liabilities if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. We have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $98 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $98 million. The asset retirement liability at the date of adoption was $104 million. As of December 31, 2002, we had recorded decommissioning liabilities of $130 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that substantially all of our nuclear decommissioning costs will be recoverable through regulated rates. Therefore, we recognized a regulatory liability of $26 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities" This statement, which was issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time they are incurred rather than when management commits to a plan of exit or disposal. It also requires the use of fair value for the measurement of such liabilities. The new standard supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This new standard was effective for exit and disposal activities initiated after December 31, 2002. Since it is applied prospectively, there will be no impact upon adoption. However, SFAS 146 could change the timing and amount of costs recognized in connection with future exit or disposal activities. FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. We currently have transactions with entities in connection with the sale of preferred securities and debt secured by bondable property, and which are reasonably possible of meeting within the scope of this interpretation, and which may meet the definition of a VIE in accordance with FIN 46. We currently consolidate those entities and believe we will continue to consolidate following the adoption of FIN 46. 11 JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF INCOME
Nov 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 - ---------------------------------------------------------------------------------------------------------------------- (In thousands) OPERATING REVENUES........................................ $2,328,415 $282,902 | $1,838,638 $1,979,297 ---------- -------- | ---------- ---------- | OPERATING EXPENSES AND TAXES: | Fuel and purchased power............................... 1,248,012 136,123 | 932,300 890,812 Nuclear operating costs................................ -- -- | -- 78,487 Other operating costs.................................. 272,890 40,670 | 237,513 303,353 ---------- -------- | ---------- ---------- Total operation and maintenance expenses............. 1,520,902 176,793 | 1,169,813 1,272,652 Provision for depreciation and amortization............ 244,759 35,124 | 205,918 235,001 General taxes.......................................... 56,049 8,919 | 56,582 64,398 Income taxes........................................... 171,496 18,400 | 113,478 124,019 ---------- -------- | ---------- ---------- Total operating expenses and taxes................... 1,993,206 239,236 | 1,545,791 1,696,070 ---------- -------- | ---------- ---------- | OPERATING INCOME.......................................... 335,209 43,666 | 292,847 283,227 | OTHER INCOME (EXPENSE).................................... 7,653 1,186 | (176,875) 24,146 ---------- -------- | ---------- ----------- | INCOME BEFORE NET INTEREST CHARGES........................ 342,862 44,852 | 115,972 307,373 ---------- -------- | ---------- ---------- | NET INTEREST CHARGES: | Interest on long-term debt............................. 92,314 14,234 | 77,205 85,220 Allowance for borrowed funds used during | construction......................................... (583) 135 | (1,665) (1,287) Deferred interest ..................................... (8,815) (2,243) | (12,557) (7,951) Other interest expense................................. (2,643) 1,080 | 9,427 9,879 Subsidiary's preferred stock dividend requirements..... 10,694 1,605 | 9,095 10,700 ---------- -------- ---------- ---------- Net interest charges................................. 90,967 14,811 | 81,505 96,561 ---------- -------- | ---------- ---------- | NET INCOME................................................ 251,895 30,041 | 34,467 210,812 | PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,125 698 | 4,547 6,904 | GAIN ON PREFERRED STOCK REACQUISITION..................... (3,589) -- | -- -- ---------- --------- | ---------- ---------- | EARNINGS ON COMMON STOCK.................................. $ 253,359 $ 29,343 | $ 29,920 $ 203,908 ========== ======== | ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 12
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS
As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------ (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $3,478,803 $3,431,823 Less-Accumulated provision for depreciation.................................... 1,343,846 1,313,259 ---------- ---------- 2,134,957 2,118,564 Construction work in progress- Electric plant............................................................... 20,687 60,482 ---------- ---------- 2,155,644 2,179,046 OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts........................................... 106,820 114,899 Nuclear fuel disposal trust.................................................... 149,738 137,098 Long-term notes receivable from associated companies........................... 20,333 20,333 Other.......................................................................... 18,202 6,643 ---------- ---------- 295,093 278,973 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 4,823 31,424 Receivables- Customers (less accumulated provisions of $4,509,000 and $12,923,000 respectively, for uncollectible accounts).................................. 247,624 226,392 Associated companies......................................................... 318 6,412 Other........................................................................ 20,134 20,729 Notes receivable from associated companies..................................... 77,358 -- Materials and supplies, at average cost........................................ 1,341 1,348 Prepayments and other.......................................................... 37,719 16,569 ---------- ---------- 389,317 302,874 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 3,199,012 3,324,804 Goodwill....................................................................... 2,000,875 1,926,526 Other.......................................................................... 12,814 27,775 ---------- ---------- 5,212,701 5,279,105 $8,052,755 $8,039,998 CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity.................................................... $3,274,069 $3,163,701 Preferred stock- Not subject to mandatory redemption.......................................... 12,649 12,649 Subject to mandatory redemption.............................................. -- 44,868 Company-obligated mandatorily redeemable preferred securities.................. 125,244 125,250 Long-term debt................................................................. 1,210,446 1,224,001 ---------- ---------- 4,622,408 4,570,469 CURRENT LIABILITIES: Currently payable long-term debt and preferred stock........................... 173,815 60,848 Short-term borrowings (Note 5)- Associated companies......................................................... -- 18,149 Accounts payable- Associated companies......................................................... 170,803 171,168 Other........................................................................ 106,504 89,739 Accrued taxes................................................................. 13,844 35,783 Accrued interest............................................................... 27,161 25,536 Other.......................................................................... 112,408 79,589 ---------- ---------- 604,535 480,812 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes.............................................. 691,721 514,216 Accumulated deferred investment tax credits.................................... 9,939 13,490 Power purchase contract loss liability ........................................ 1,710,968 1,968,823 Nuclear fuel disposal costs.................................................... 166,191 163,377 Nuclear plant decommissioning costs............................................ 135,355 137,424 Other.......................................................................... 111,638 191,387 ---------- ---------- 2,825,812 2,988,717 COMMITMENTS AND CONTINGENCIES (Notes 3 and 6)................................................................. ---------- ---------- $8,052,755 $8,039,998 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. 13
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2002 2001 - ---------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, par value $10 per share, authorized 16,000,000 shares 15,371,270 shares outstanding.................................................... $ 153,713 $ 153,713 Other paid-in capital.............................................................. 3,029,218 2,981,117 Accumulated other comprehensive loss (Note 4E)..................................... (865) (472) Retained earnings (Note 4A)........................................................ 92,003 29,343 ------------ ---------- Total common stockholder's equity................................................ 3,274,069 3,163,701 ------------ ---------- Number of Shares Optional Outstanding Redemption Price ---------------- -------------------- 2002 2001 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK (Note 4B): Cumulative, without par value- Authorized 125,000 shares Not Subject to Mandatory Redemption: 4% Series........................ 125,000 125,000 $106.50 $13,313 12,649 12,649 Subject to Mandatory Redemption: 8.65% Series J..................... -- 250,001 101.30 $25,325 -- 26,750 7.52% Series K..................... -- 265,000 103.76 27,496 -- 28,951 Redemption Within One Year......... -- -- -- (10,833) ------- ------- ------ ------- ------ -------- Total Subject to Mandatory Redemption..................... -- 515,001 $52,821 -- 44,868 ======= ======= ======= ------ ------- COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY LIMITED PARTNERSHIP HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES (NOTE 4C): Cumulative, $25 par value - Authorized 5,000,000 shares Subject to Mandatory Redemption: 8.56% due 2044.................................................................. 125,244 125,250 LONG-TERM DEBT (Note 4D): First mortgage bonds: 9.000% due 2002................................................................... -- 50,000 6.375% due 2003................................................................... 150,000 150,000 7.125% due 2004................................................................... 160,000 160,000 6.780% due 2005................................................................... 50,000 50,000 6.850% due 2006................................................................... 40,000 40,000 8.250% due 2006................................................................... 23,053 50,000 7.900% due 2007................................................................... 18,361 40,000 7.125% due 2009................................................................... 6,300 6,300 7.100% due 2015................................................................... 12,200 12,200 9.200% due 2021................................................................... 22,963 50,000 8.320% due 2022................................................................... 40,000 40,000 8.550% due 2022................................................................... 13,623 30,000 8.820% due 2022................................................................... -- 12,000 8.850% due 2022................................................................... -- 38,000 7.980% due 2023................................................................... 40,000 40,000 7.500% due 2023................................................................... 125,000 125,000 8.450% due 2025................................................................... 50,000 50,000 6.750% due 2025................................................................... 150,000 150,000 ---------- ---------- Total first mortgage bonds...................................................... 901,500 1,093,500 ---------- ---------- Secured notes: 6.450% due 2006................................................................... 150,000 150,000 4.190% due 2007................................................................... 91,111 -- 5.390% due 2010................................................................... 52,297 -- 5.810% due 2013................................................................... 77,075 -- 6.160% due 2017................................................................... 99,517 -- ---------- ---------- Total secured notes............................................................. 470,000 150,000 ---------- ---------- Unsecured notes: 7.69% due 2039.................................................................... 2,984 2,998 ---------- ----------- Net unamortized premium on debt..................................................... 9,777 27,518 ---------- ---------- Long-term debt due within one year.................................................. (173,815) (50,015) ---------- ----------- Total long-term debt............................................................ 1,210,446 1,224,001 ---------- ---------- TOTAL CAPITALIZATION................................................................... $4,622,408 $4,570,469 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 14
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated Common Stock Other Other Comprehensive Number Par Paid-In Comprehensive Retained Income of Shares Value Capital Income (Loss) Earnings ------------- --------- ----- ------- ------------- -------- (Dollars in thousands) Balance, January 1, 2000....................... 15,371,270 $153,713 $ 510,769 $ 7 $ 720,878 Net income.................................. $210,812 210,812 Minimum pension liability................... (15) (15) -------- Comprehensive income........................ 210,797 -------- Cash dividends on preferred stock........... (6,904) Cash dividends on common stock.............. (130,000) - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000..................... 15,371,270 153,713 510,769 (8) 794,786 Net income.................................. 34,467 34,467 Net unrealized gain on investments.......... 2 2 Net unrealized gain on derivative instruments............................... 768 768 -------- Comprehensive income........................ 35,237 -------- Cash dividends on preferred stock........... (4,547) Cash dividends on common stock ............ (175,000) - -------------------------------------------------------------------------------------------------------------------- Balance, November 6, 2001...................... 15,371,270 153,713 510,769 762 649,706 Purchase accounting fair value adjustment... 2,470,348 (762) (649,706) - -------------------------------------------------------------------------------------------------------------------- Balance, November 7, 2001...................... 15,371,270 153,713 2,981,117 -- -- Net income.................................. 30,041 30,041 Net unrealized gain (loss) on derivative instruments............................... (472) (472) -------- Comprehensive income........................ 29,569 -------- Cash dividends on preferred stock........... (698) - --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001..................... 15,371,270 153,713 2,981,117 (472) 29,343 Net income.................................. 251,895 251,895 Net unrealized gain (loss) on derivative instruments............................... (393) (393) -------- Comprehensive income........................ $251,502 -------- Cash dividends on preferred stock........... 1,465 Cash dividends on common stock.............. (190,700) Purchase accounting fair value adjustment . 48,101 - -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002..................... 15,371,270 $153,713 $3,029,218 $ (865) $ 92,003 ==================================================================================================================== CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemption -------------------- --------------------- Number Carrying Number Carrying of Shares Value of Shares Value --------- -------- --------- -------- (Dollars in thousands) Balance, January 1, 2000............ 125,000 $12,649 5,840,000 $209,000 Redemptions- 7.52% Series.................... (50,000) (5,000) 8.65% Series.................... ( 166,666) (16,667) ----------------------------------------------------------------------------------------- Balance, December 31, 2000.......... 125,000 12,649 5,623,334 187,333 Redemptions- 7.52% Series.................... (25,000) (2,500) 8.65% Series.................... (83,333) (8,333) Purchase accounting fair value adjustment............. 4,451 ----------------------------------------------------------------------------------------- Balance, December 31, 2001.......... 125,000 12,649 5,515,001 180,951 Redemptions- 7.52% Series.................... (265,000) (28,951) 8.65% Series.................... (250,001) (26,750) Purchase accounting fair value adjustment............. (6) ----------------------------------------------------------------------------------------- Balance, December 31, 2002.......... 125,000 $12,649 5,000,000 $125,244 ========================================================================================= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
15 JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 - ----------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income........................................................ $ 251,895 $ 30,041 | $ 34,467 $ 210,812 Adjustments to reconcile net income to net | cash from operating activities: | Provision for depreciation and amortization.................. 244,759 35,124 | 205,918 235,001 Nuclear fuel and lease amortization.......................... -- -- | -- 11,472 Other amortization........................................... 849 1,360 | 23,025 34,563 Deferred costs recoverable as regulatory assets.............. (285,065) (25,471) | (29,312) (229,321) Deferred income taxes, net................................... 115,866 5,609 | (58,132) 270,479 Investment tax credits, net.................................. (3,551) (540) | (3,057) (15,027) Receivables.................................................. (14,542) 7,050 | 27,177 11,766 Materials and supplies....................................... 7 2 | (842) (268) Accounts payable............................................. 16,399 (5,060) | (44,498) 51,633 Other (Note 7)............................................... (17,642) 20,563 | 66,328 (230,100) --------- -------- | --------- --------- Net cash provided from operating activities................ 308,975 68,678 | 221,074 351,010 --------- -------- | --------- --------- | CASH FLOWS FROM FINANCING ACTIVITIES: | New Financing- | Long-term debt............................................... 318,106 -- | 148,796 -- Short-term borrowings, net................................... -- -- | -- 29,200 Redemptions and Repayments- | Preferred stock.............................................. (51,500) -- | (10,833) (21,667) Long-term debt............................................... (196,033) (40,000) | -- (40,000) Short-term borrowings, net................................... (18,149) (1,851) | (9,200) -- Capital lease payments....................................... -- -- | -- (48,516) Dividend Payments- | Common stock................................................. (190,700) -- | (175,000) (130,000) Preferred stock.............................................. (2,125) (698) | (4,547) (7,065) --------- -------- | --------- ---------- Net cash used for financing activities..................... (140,401) (42,549) | (50,784) (218,048) --------- -------- | ---------- ---------- | CASH FLOWS FROM INVESTING ACTIVITIES: | Property additions............................................. (97,346) (21,487) | (141,030) (144,389) Contributions to decommissioning trusts........................ -- (202) | (1,004) (130,444) Sale of investments............................................ -- -- | -- 74,797 Loans to associated companies.................................. (77,358) -- | -- -- Other.......................................................... (20,471) (1,078) | (2,215) (624) --------- -------- | ----------- --------- Net cash used for investing activities..................... (195,175) (22,767) | (144,249) (200,660) --------- -------- | --------- ---------- | | Net increase (decrease) in cash and cash equivalents.............. (26,601) 3,362 | 26,041 (67,698 Cash and cash equivalents at beginning of period.................. 31,424 28,062 | 2,021 69,719 --------- -------- | --------- --------- Cash and cash equivalents at end of period........................ $ 4,823 $ 31,424 | $ 28,062 $ 2,021 ========= ======== | ========= ========= | SUPPLEMENTAL CASH FLOWS INFORMATION: | Cash Paid During the Year- | Interest (net of amounts capitalized)........................ $ 92,152 $ 4,787 | $ 95,509 $ 99,961 ========= ======== | ========= ========= Income taxes (refund)........................................ $ 83,776 $ 20,586 | $ 19,365 $ (50,105) ========= ======== | ========= ========= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 16
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF TAXES
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 - --------------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: Real and personal property....................................... $ 4,362 $ 283 | $ 3,589 $ 4,093 State gross receipts............................................. -- 1,269 | -- -- Social security and unemployment................................. -- (1) | 7 -- New Jersey Transitional Energy Facilities Assessment*............ 39,387 6,765 | 42,418 47,521 Other............................................................ 12,300 603 | 10,568 12,784 -------- --------- | --------- --------- Total general taxes....................................... $ 56,049 $ 8,919 | $ 56,582 $ 64,398 ======== ========= | ========= ========= | PROVISION FOR INCOME TAXES: | Currently payable- | Federal....................................................... $ 55,731 $ 11,827 | $ 41,826 $(109,572) State......................................................... 13,809 3,205 | 19,415 (26,005) -------- --------- | --------- --------- `69,540 15,032 | 61,241 (135,577) -------- --------- | --------- --------- Deferred, net- | Federal....................................................... 88,758 4,268 | (36,210) 209,127 State......................................................... 27,108 1,341 | (21,922) 61,352 -------- --------- | --------- ---------- 115,866 5,609 | (58,132) 270,479 -------- --------- | --------- --------- Investment tax credit amortization............................... (3,551) (540) | (3,057) (15,027) -------- --------- | --------- --------- Total provision for income taxes.......................... $181,855 $ 20,101$ | $ 52 $ 119,875 ======== ========== | ========= ========= | INCOME STATEMENT CLASSIFICATION | OF PROVISION FOR INCOME TAXES: | Operating income................................................. $171,496 $ 18,400 | $ 113,478 $ 124,019 Other income..................................................... 10,359 1,701 | (113,426) (4,144) -------- --------- | --------- --------- Total provision for income taxes.......................... $181,855 $ 20,101 | 52 $ 119,875 ======== ========= | ========= ========= | RECONCILIATION OF FEDERAL INCOME TAX | EXPENSE AT STATUTORY RATE TO TOTAL | PROVISION FOR INCOME TAXES: | Book income before provision for income taxes.................... $433,749 $ 50,142 | $ 34,519 $ 330,688 ======== ========= | ========= ========= Federal income tax expense at statutory rate..................... $151,812 $ 17,550 | $ 12,082 $ 115,741 Increases (reductions) in taxes resulting from- | Amortization of investment tax credits........................ (3,550) (540) | (3,057) (15,027) Depreciation.................................................. 7,154 226 | 3,563 3,230 State income tax, net of federal benefit...................... 27,111 3,077 | 4,355 21,987 Allocated share of consolidated tax savings................... -- -- | (8,509) -- Sale of generation assets..................................... -- -- | -- (6,239) Other, net.................................................... (672) (212) | (8,382) 183 -------- --------- | ---------- --------- Total provision for income taxes.......................... $181,855 $ 20,101 | $ 52 $ 119,875 ======== ========= | ========== ========= | ACCUMULATED DEFERRED INCOME TAXES AT | DECEMBER 31: | Property basis differences....................................... $297,983 $ 288,255 | $ 302,476 Nuclear decommissioning.......................................... 44,775 59,716 | 97,817 Deferred sale and leaseback costs................................ (16,451) (16,240) | (15,605) Purchase accounting basis difference............................. (1,253) (71,900) | -- Sale of generation assets........................................ (17,861) 184,625 | 235,923 Regulatory transition charge..................................... 224,117 123,042 | 99,930 Provision for rate refund........................................ (29,370) (46,942) | (46,942) Customer receivables for future income taxes..................... (5,336) 16,749 | 33,234 Oyster Creek securitization...................................... 202,448 -- | -- Other............................................................ (7,331) (23,089) | (40,786) -------- --------- | --------- Net deferred income tax liability......................... $691,721 $ 514,216 | $ 666,047 ======== ========= | ========= * Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include Jersey Central Power & Light Company (Company) and its wholly owned subsidiaries. All significant intercompany transactions have been eliminated. The Company is a wholly owned subsidiary of FirstEnergy Corp. FirstEnergy also holds directly all of the issued and outstanding common shares of Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE), American Transmission Systems, Inc. (ATSI), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The Company, Met-Ed and Penelec were formerly wholly owned subsidiaries of GPU, Inc., which merged with FirstEnergy on November 7, 2001. Pre-merger and post-merger period financial results are separated by a heavy black line. The Company follows the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the New Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Certain prior year amounts have been reclassified to conform with the current year presentation. (A) CONSOLIDATION- The Company consolidates all majority-owned subsidiaries, after eliminating the effects of intercompany transactions. Non-majority owned investments, including investments in limited liability companies, partnerships and joint ventures, are accounted for under the equity method when the Company is able to influence their financial or operating policies. Investments in corporations resulting in voting control of 20% or more are presumed to be equity method investments. Limited partnerships are evaluated in accordance with SEC Staff D-46, "Accounting for Limited Partnership Investments" and American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence. For all remaining investments (excluding those within the scope of Statement of Financial Accounting Standards (SFAS) 115, the Company applies the cost method. (B) REVENUES- The Company's principal business is providing electric service to customers in New Jersey. The Company's retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service provided through the end of the year. See Note 7 - Other Information for discussion of reporting of independent system operator transactions. Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2002 or 2001, with respect to any particular segment of the Company's customers. (C) REGULATORY PLAN- New Jersey continues to evolve to a competitive electric utility marketplace. In 2001, the NJBPU issued a Final Decision and Order (Final Order) with respect to the Company's rate unbundling, stranded cost and restructuring filings, which superseded its 1999 Summary Order. The Final Order confirmed rate reductions set forth in the 1999 Summary Order, which remain in effect at increasing levels through July 2003, confirmed the right of customers to select their generation supplier and deregulated electric generation service costs. The Final Order also confirmed the establishment of a non-bypassable societal benefits charge to recover costs including nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable market transition charge primarily to recover stranded costs. The NJBPU has deferred making a final determination of the net proceeds and stranded costs related to prior generating asset divestitures until the Company'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 the Company's net income since the contingency existed prior to the Company being acquired by FirstEnergy. 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, the Company 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 (see Note 4F). 18 The Company obtains its supply of electricity almost entirely from contracted and open market purchases. The Company is permitted to defer for future collection from customers the amounts by which its costs for supplying non-shopping customers and costs incurred under non-utility generation agreements exceed amounts collected through its Basic Generation Service (BGS) and market transition charge rates. As of December 31, 2002, the accumulated deferred cost balance totaled approximately $549 million. The NJBPU also allowed securitization of the Company's deferred balance to the extent permitted by law upon application by the Company 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, including the Company, were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. On August 1, 2002, the Company 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 market transition charge and societal benefits charge 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. The Administrative Law Judge's recommended decision is due in June 2003 and the NJBPU's subsequent decision is due in July 2003. 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 the Company'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 a hourly price bid (applicable to all large industrial customers) process. The Company will sell all self-supplied energy (non-utility generation and owned generation) to the wholesale market with offsets to its deferred energy cost balances. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," was discontinued in 1999 with respect to the Company's generation operations. The Company subsequently divested substantially all of its generating assets. The SEC issued interpretive guidance regarding asset impairment measurement, concluding that any supplemental regulated cash flows such as a Competitive Transition Charge should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Net assets included in utility plant relating to operations for which the application of SFAS 71 was discontinued were $44 million as of December 31, 2002. (D) PROPERTY, PLANT AND EQUIPMENT- As a result of the merger, a portion of the Company's property, plant and equipment was adjusted to reflect fair value. The majority of the Company's property, plant and equipment is reflected at original cost since such assets remain subject to rate regulation on a historical cost basis. In addition to its wholly owned facilities, the Company holds a 50% ownership interest in Yards Creek Pumped Storage Facility, and its net book value was approximately $21.3 million as of December 31, 2002. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 3.5% in 2002, 3.4% in 2001 and 3.3% in 2000. Annual depreciation expense in 2002 included approximately $26.2 million for future decommissioning costs applicable to the Company's ownership in Unit 2 of the Three Mile Island Nuclear Plant (TMI-2), a demonstration nuclear reactor (Saxton Nuclear Experimental Facility) owned by a wholly owned subsidiary of the Company (in conjunction with Met-Ed and Penelec) and decommissioning liabilities for its previously divested nuclear generating units. The Company's share of the future obligation to decommission these units is approximately $132.0 million in current dollars and (using a 4.0% escalation rate) approximately $210.1 million in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Decommissioning of the demonstration nuclear reactor is expected to be completed in 2003; payments for decommissioning of the nuclear generating units are expected to begin in 2014, when actual decommissioning work is expected to begin. The Company has recovered approximately $34.0 million for future decommissioning through its electric rates from customers through December 31, 2002. The Company has also recognized an estimated liability of approximately $9.9 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992. 19 In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead, if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. The Company has identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $98 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $98 million. The asset retirement liability at the date of adoption was $104 million. As of December 31, 2002, the Company had recorded decommissioning liabilities of $130 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that substantially all of the nuclear decommissioning costs will be recoverable through regulated rates. Therefore, the Company recognized a regulatory liability of $26 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The FASB approved SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using purchase accounting. The provisions of the new standard relating to the determination of goodwill and other intangible assets have been applied to the FirstEnergy/GPU merger, which was accounted for as a purchase transaction, and have not materially affected the accounting for this transaction. Under SFAS 142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill is tested for impairment at least on an annual basis - based on the results of the transition analysis and the 2002 annual analysis, no impairment of the Company's goodwill is required. (E) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 4B). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date, resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows: 2002 2001 2000 ---------------------------------------------------------------------------- Valuation assumptions: Expected option term (years). 8.1 8.3 7.6 Expected volatility.......... 23.31% 23.45% 21.77% Expected dividend yield...... 4.36% 5.00% 6.68% Risk-free interest rate...... 4.60% 4.67% 5.28% Fair value per option.......... $6.45 $4.97 $2.86 ---------------------------------------------------------------------------- The effects of applying fair value accounting to the FirstEnergy's stock options would not materially affect the Company's net income. 20 (F) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Results for the period January 1, 2001 through November 6, 2001 were included in the final consolidated federal income tax return of GPU, and results for the period November 7, 2001 through December 31, 2001 were included in FirstEnergy's 2001 consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Company recognizing the tax benefit for any tax losses or credits it contributed to the consolidated return. (G) RETIREMENT BENEFITS- Effective December 31, 2001, the Company's defined benefit pension plan was merged into FirstEnergy's defined benefit pension plan. FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all of the Company's full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. FirstEnergy uses the projected unit credit method for funding purposes. The assets of the pension plan consist primarily of common stocks, United States government bonds and corporate bonds. Costs for the year 2001 include the former GPU companies' pension and other postretirement benefit costs for the period November 7, 2001 through December 31, 2001. The Company provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company pays insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Company. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheet as of December 31: 21
Other Pension Benefits Postretirement Benefits ---------------- ----------------------- 2002 2001 2002 2001 - ------------------------------------------------------------------------------------------------ (In millions) Change in benefit obligation: Benefit obligation as of January 1........ $3,547.9 $1,506.1 $ 1,581.6 $ 752.0 Service cost.............................. 58.8 34.9 28.5 18.3 Interest cost............................. 249.3 133.3 113.6 64.4 Plan amendments........................... -- 3.6 (121.1) -- Actuarial loss............................ 268.0 123.1 440.4 73.3 Voluntary early retirement program........ -- -- -- 2.3 GPU acquisition........................... (11.8) 1,878.3 110.0 716.9 Benefits paid............................. (245.8) (131.4) (83.0) (45.6) ------------------------------------------------------------------------------------------- Benefit obligation as of December 31...... 3,866.4 3,547.9 2,070.0 1,581.6 ------------------------------------------------------------------------------------------- Change in fair value of plan assets: Fair value of plan assets as of January 1. 3,483.7 1,706.0 535.0 23.0 Actual return on plan assets.............. (348.9) 8.1 (57.1) 12.7 Company contribution...................... -- -- 37.9 43.3 GPU acquisition........................... -- 1,901.0 -- 462.0 Benefits paid............................. (245.8) (131.4) (42.5) (6.0) ------------------------------------------------------------------------------------------- Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0 -------------------------------------------------------------------------------------------- Funded status of plan..................... (977.4) (64.2) (1,596.7) (1,046.6) Unrecognized actuarial loss............... 1,185.8 222.8 751.6 212.8 Unrecognized prior service cost........... 78.5 87.9 (106.8) 17.7 Unrecognized net transition obligation.... -- -- 92.4 101.6 ------------------------------------------------------------------------------------------- Net amount recognized..................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) =========================================================================================== Consolidated Balance Sheets classifications: Prepaid (accrued) benefit cost............ $(548.6) $ 246.5 $ (859.5) $ (714.5) Intangible asset.......................... 78.5 -- -- -- Accumulated other comprehensive loss...... 757.0 -- -- -- ------------------------------------------------------------------------------------------- Net amount recognized..................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) ============================================================================================ Assumptions used as of December 31: Discount rate............................. 6.75% 7.25% 6.75% 7.25% Expected long-term return on plan assets.. 9.00% 10.25% 9.00% 10.25% Rate of compensation increase............. 3.50% 4.00% 3.50% 4.00% Net pension and other postretirement benefit costs for the two years ended December 31, 2002 were computed as follows: Other Pension Benefits Postretirement Benefits -------------------- ----------------------- 2002 2001 2002 2001 -------------------------------------------------------------------------------------------------- (In millions) Service cost........................... $ 58.8 $ 34.9 $ 28.5 $18.3 Interest cost.......................... 249.3 133.3 113.6 64.4 Expected return on plan assets......... (346.1) (204.8) (51.7) (9.9) Amortization of transition obligation (asset).............................. -- (2.1) 9.2 9.2 Amortization of prior service cost..... 9.3 8.8 3.2 3.2 Recognized net actuarial loss (gain)... -- -- 11.2 4.9 Voluntary early retirement program..... -- 6.1 -- 2.3 -------------------------------------------------------------------------------------------------- Net periodic benefit cost (income)..... $ (28.7) $ (23.8) $114.0 $92.4 ==================================================================================================
The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. A significant portion of the services provided to the Company are from affiliates, GPU Service, Inc. (GPUS) and FirstEnergy Service Company (FECO) (see Note 1H). Therefore, substantially all of the employees are with GPUS which bills the Company for services rendered. See Note 7D for the Company's amount of net pension and other postretirement benefit costs reflected in its Consolidated Statements of Income. 22 (H) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily GPUS and FirstEnergy Solutions (FES). During the three years ended December 31, 2002, GPUS provided legal, accounting, financial and other services to the Company. The Company also entered into sale and purchase transactions with affiliates (Met-Ed and Penelec) during the period. Through the BGS auction process, FES is an alternate supplier of power to the Company. FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from its affiliates, GPUS and FECO, both subsidiaries of FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act (PUHCA). The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas: the ratio of each company's amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers and other factors; and specific departmental charge ratios. Management believes that these allocation methods are reasonable. (I) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31: 2002 2001 - ------------------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value - ------------------------------------------------------------------------------- (In millions) Long-term debt..................... $1,374 $ 1,415 $1,246 $1,250 Preferred stock.................... $ 125 $ 127 $ 176 $ 180 Investments other than cash and cash equivalents............. $ 258 $ 258 $ 253 $ 252 The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to the Company's ratings. In 2001, long-term debt and preferred stock subject to mandatory redemption were recognized at fair value in connection with the merger. The fair value of investments other than cash and cash equivalents represents cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. The Company has no securities held for trading purposes. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "Investments other than cash and cash equivalents" in the table above) consist of equity securities, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized losses were approximately $0.06 million and interest and dividend income totaled approximately $3.6 million. On January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an amendment of FASB Statement No. 133." The adoption resulted in the recognition of derivative assets on the Consolidated Balance Sheet as of January 1, 2001 in the amount of $21.8 million with offsetting amounts, net of tax, recorded in Accumulated Other Comprehensive Income, of $5.1 million, and in Regulatory Assets, of $13 million. The Company is exposed to financial risks resulting from the fluctuation of commodity prices, including electricity and natural gas. To manage the volatility relating to these exposures, the Company uses a variety of non-derivative and derivative instruments, including forward contracts, options and futures contracts. These derivatives are used principally for hedging purposes. The Company has a Risk Policy Committee, comprised of FirstEnergy executive officers, which exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. The Company uses derivatives to hedge the risk of price fluctuations. The Company's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The majority of the Company's forward commodity contracts are considered "normal purchases and sales," as defined by SFAS 133, and are therefore excluded from the scope of SFAS 138. The forward contracts, options and futures contracts determined to be within the scope of SFAS 133 are accounted for as cash flow hedges and expire on various dates through 2003. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. There is currently a net deferred loss of $0.4 million included in Accumulated Other Comprehensive Loss as of December 31, 2002 related to derivative hedging activity, which will be reclassified to earnings during the next twelve months as hedged transactions occur. (J) REGULATORY ASSETS- The Company recognizes, as regulatory assets, costs which the FERC and NJBPU have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Company's regulatory plan. The Company continues to bill and collect cost-based rates for its transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2002 2001 ----------------------------------------------------------------------------- (In millions) Regulatory transition charge................... $2,801.7 $2,844.7 Societal benefits charge....................... 143.8 166.6 Property losses and unrecovered plant costs.... 87.8 104.1 Customer receivables for future income taxes... 34.5 52.4 Employee postretirement benefit costs.......... 33.2 36.5 Loss on reacquired debt........................ 17.4 19.3 Spent fuel disposal costs...................... 8.8 20.2 Other.......................................... 71.8 81.0 ----------------------------------------------------------------------------- Total....................................... $3,199.0 $3,324.8 ============================================================================= 2. MERGER: On November 7, 2001, the merger of FirstEnergy and GPU became effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000. As a result of the merger, GPU's former wholly owned subsidiaries, including the Company, became wholly owned subsidiaries of FirstEnergy. The merger was accounted for by the purchase method of accounting. The assets acquired and liabilities assumed were recorded at estimated fair values as determined by FirstEnergy's management based on information currently available and on current assumptions as to future operations. Merger purchase accounting adjustments recorded in the records of the Company primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. Other assets and liabilities were not adjusted since they remain subject to rate regulation on a historical cost basis. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. During 2002, certain pre-acquisition contingencies and other final adjustments to the fair values of the assets acquired and liabilities assumed were reflected in the final allocation of the purchase price. These adjustments primarily related to: (1) final actuarial calculations related to pension and postretirement benefit obligations and (2) return to accrual adjustments for income taxes. As a result of these adjustments, goodwill increased by approximately $74.3 million. As of December 31, 2002, the Company had recorded goodwill of approximately $2.0 billion related to the merger. 24 3. LEASES: Consistent with regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Prior to the sale of its nuclear generating facilities (completed in 2000), the Company's capital lease obligations related primarily to nuclear fuel lease agreements with nonaffiliated fuel trusts for the plants. In 2000, total rentals related to these capital leases were $13.0 million, comprised of an interest element of $1.5 million and other costs of $11.5 million. The Company's most significant operating lease relates to the sale and leaseback of a portion of its ownership interest in the Merrill Creek Reservoir project. The interest element related to this lease was $1.2 million, $1.2 million and $0.4 million for the years 2002, 2001 and 2000, respectively. As of December 31, 2002, the future minimum lease payments on the Company's Merrill Creek operating lease, net of reimbursements from sublessees, are: $3.2 million, $1.2 million, $1.7 million, $1.6 million and $1.6 million for the years 2003 through 2007, respectively, and $56.7 million for the years thereafter. The Company is recovering its Merrill Creek lease payments, net of reimbursements, through its distribution rates. 4. CAPITALIZATION: (A) RETAINED EARNINGS- The merger purchase accounting adjustments included resetting the retained earnings balance to zero as of the November 7, 2001 merger date. In general, the Company's first mortgage bond (FMB) indentures restrict the payment of dividends or distributions on or with respect to the Company's common stock to amounts credited to earned surplus since approximately the date of its indenture. At such date, the Company had a balance of $1.7 million in its earned surplus account, which would not be available for dividends or other distributions. As of December 31, 2002, the Company had retained earnings available to pay common stock dividends of $90.3 million, net of amounts restricted under the Company's FMB indentures. (B) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 2002 2001 2000 - ------------------------------------------------------------------------------ Restricted common shares granted......... 36,922 133,162 208,400 Weighted average market price ........... $36.04 $35.68 $26.63 Weighted average vesting period (years).. 3.2 3.7 3.8 Dividends restricted..................... Yes * Yes ---------------------------------------------------------------------------- * FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2002, there were 296,008 stock units outstanding. 25 Stock option activities under the FE Programs for the past three years were as follows: Number of Weighted Average Stock Option Activities Options Exercise Price - ------------------------------------------------------------------------------ Balance, January 1, 2000............... 2,153,369 $25.32 (159,755 options exercisable).......... 24.87 Options granted...................... 3,011,584 23.24 Options exercised.................... 90,491 26.00 Options forfeited.................... 52,600 22.20 Balance, December 31, 2000............ 5,021,862 24.09 (473,314 options exercisable).......... 24.11 Options granted...................... 4,240,273 28.11 Options exercised.................... 694,403 24.24 Options forfeited.................... 120,044 28.07 Balance, December 31, 2001............. 8,447,688 26.04 (1,828,341 options exercisable)........ 24.83 Options granted...................... 3,399,579 34.48 Options exercised.................... 1,018,852 23.56 Options forfeited.................... 392,929 28.19 Balance, December 31, 2002............ 10,435,486 28.95 (1,400,206 options exercisable)........ 26.07 As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 1E - Stock-Based Compensation. (C) PREFERRED AND PREFERENCE STOCK- Preferred stock may be redeemed by the Company, in whole or in part, with 30-90 days' notice. (D) COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF LIMITED PARTNERSHIP HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES- JCP&L Capital, L.P. is a special-purpose limited partnership in which a subsidiary of the Company is the sole general partner. The limited partnership invested the gross proceeds from the sale of $125.0 million at 8.56% of monthly income preferred securities (MIPS) in $128.9 million of the Company's 8.56% subordinated debentures. The sole assets of the limited partnership are these subordinated debentures, which have the same rate and maturity date as the preferred securities. The Company has effectively provided a full and unconditional guarantee of its obligations under its limited partnership's MIPS, to the extent that there is sufficient cash on hand to permit such payments and funds legally available therefor, and payments on liquidation or redemption with respect to the MIPS. Distributions on the limited partnership's MIPS (and interest on the subordinated debentures) may be deferred for up to 60 months, but the Company may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full. The limited partnership's MIPS, which mature in 2044 and have a liquidation value of $25.00 per security, are redeemable at the option of the Company at 100% of their principal amount. 26 (E) LONG-TERM DEBT- The Company's first mortgage bond indenture, which secures all of the Company's FMBs, serve as a direct first mortgage lien on substantially all of the Company's property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of these relate to the nonpayment of interest and/or principal on debt, which could trigger a default. Cross-default provisions also exist between FirstEnergy and the Company. Based on the amount of bonds authenticated by the Trustee through December 31, 2002 the Company's annual improvement fund requirements for all bonds issued under the mortgage amount to $15.7 million. The Company expects to fulfill its improvement fund obligation by providing refundable bonds to the Trustee. Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) ------------------------ 2003........ $173.8 2004........ 175.9 2005........ 66.9 2006........ 230.6 2007........ 36.7 ------------------------- (F) SECURITIZED TRANSITION BONDS- On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of the Company, sold $320 million of transition bonds to securitize the recovery of the Company's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. The Company does not own nor did it purchase any of the transition bonds, which are included in long-term debt on and the Company's Consolidated Balance Sheet. The transition bonds represent obligations only of the Issuer and are collateralized solely by the equity and assets of the Issuer, which consist primarily of bondable transition property. The bondable transition property is solely the property of the Issuer. Bondable transition property represents the irrevocable right of a utility company to charge, collect and receive from its customers, through a non-bypassable transition bond charge, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. The Company, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the transition bond charge, pursuant to a servicing agreement with the Issuer. The Company is entitled to a quarterly servicing fee of $100,000 that is payable from transition bond charge collections. (G) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with the Company's parent. As of December 31, 2002, accumulated other comprehensive loss consisted of unrealized losses on derivative instrument hedges of $0.9 million. 5. SHORT-TERM BORROWINGS: The Company may borrow from its affiliates on a short-term basis. As of December 31, 2002, the Company had no short-term borrowings outstanding. 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $462 million for property additions and improvements from 2003 through 2007, of which approximately $102 million is applicable to 2003. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on 27 its present ownership interest in TMI-2, the Company is exempt from any potential assessment under the industry retrospective rating plan. The Company is also insured as to its interest in TMI-2 under a policy issued to the operating company for the plant. Under this policy, $150 million is provided for property damage and decontamination and decommissioning costs. Under this policy, the Company can be assessed a maximum of approximately $0.2 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at TMI-2 exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs. (C) ENVIRONMENTAL MATTERS- The Company has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, 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 Company's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, the Company has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered through a non-bypassable societal benefits charge. The Company has total accrued liabilities aggregating approximately $47.1 million as of December 31, 2002. The Company does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. (D) OTHER LEGAL PROCEEDINGS- Various lawsuits, claims and proceedings related to the Company's normal business operations are pending against the Company, the most significant of which are described below. The Company has a 25% ownership interest in TMI-2, which was damaged during a 1979 accident. As a result of the accident, claims for alleged personal injury were filed against the Company, Met-Ed, Penelec and GPU (the defendants) in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by the defendants and dismissed the ten initial "test cases" which had been selected for a test case trial. In January 2002, the District Court granted the defendants' July 2001 motion for summary judgment on the remaining 2,100 pending claims. In February 2002, the plaintiffs filed a notice of appeal to the United States Court of Appeals for the Third Circuit. In December 2002, the Court of Appeals refused to hear the appeal, which effectively ended further legal action for those claims. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including the service territory of the Company. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, the Company provided unsafe, inadequate or improper service to its customers. In July 1999, two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court against the Company and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the Company's service territory. In May 2001, the court denied without prejudice the Company's motion seeking decertification of the class. Discovery continues in the class action, but no trial date has been set. In October 2001, the court held argument on the plaintiffs' motion for partial summary judgment, which contends that the Company is bound to several findings of the NJBPU investigation. The plaintiffs' motion was denied by the Court in November 2001 and the plaintiffs' motion to file an appeal of this decision was denied by the New Jersey Appellate Division. The Company has also filed a motion for partial summary judgment that is currently pending before the Superior Court. The Company is unable to predict the outcome of these matters. 28 7. OTHER INFORMATION: The following represents the financial data which includes supplemental unaudited prior years' information as compared to consolidated financial statements and notes previously reported in 2001 and 2000. (A) CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2002 ---- ---- ---- ---- Other Cash Flows from Operating Activities: Accrued taxes............................. $(21,939) $ 2,675 | $24,272 $ 4,242 Accrued interest.......................... 1,625 9,501 | (7,590) 898 Retail rate refunds obligation payments... (43,016) -- | -- -- Prepayments and other..................... (21,149) 16,436 | 63,909 (73,916) All other................................. 66,837 (8,049) | (14,263) (161,324) -------- -------- | ------- --------- Other cash used for operating activities $(17,642) $20,563 | $66,328 $(230,100) ======== ======= | ======= =========
(B) REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS The Company records purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." The aggregate purchase and sales transactions for the three years ended December 31, 2002, are summarized as follows: Nov. 7-Dec. 31, Jan. 1-Nov. 6, 2002 2001 2001 2000 ------------------------------------------------------- (In millions) Sales..... $136 $ 2 | $ 28 $87 Purchases. 101 16 | 188 66 -------------------------------|----------------------- The Company's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from the PJM ISO from power sales (as reflected in the table above) during periods when the Company had additional available power capacity. Revenues also include sales by the Company of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when the Company required additional power to meet its retail load requirements. (C) TRANSACTIONS WITH AFFILIATED COMPANIES- The primary affiliated companies transactions are as follows: Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2000 - ------------------------------------------------------------------------------ (In millions) Operating Revenues: Wholesale sales-affiliated companies... $ 17.6 $ 2.4 | $17.3 $ 3.0 | Operating Expenses: | GPU Service, Inc. support services..... 140.4 21.0 | 120.0 259.0 Power purchased from other affiliates.. 26.1 3.4 | 16.1 48.1 Power purchased from FES............... 17.9 7.5 | -- -- - ----------------------------------------------------------------------------- (D) RETIREMENTS BENEFITS (1) Net pension and other postretirement benefit costs (income) for the three years ended December 31, 2002 are approximately as follows: Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2000 - ------------------------------------------------------------------------------ (In millions) Pension Benefits....................... $(19.6) $(6.7) | $(33.4) $(10.6) Other Postretirement Benefits.......... 5.3 1.7 | 8.3 14.9 - ------------------------------------------------------------------------------ (1) Includes estimated portion of benefit costs included in billings from GPUS. 29 8 . RECENTLY ISSUED ACCOUNTING STANDARDS: FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Company does not believe that implementation of FIN 45 will be material but it will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. The Company currently has transactions with entities in connection with the sale of preferred securities, which may fall within the scope of this interpretation, and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. The Company currently consolidates these entities and believes it will continue to consolidate following the adoption of FIN 46. 9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
March 31, June 30, September 30, December 31, Three Months Ended 2002 2002 2002 2002 - ------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues.......................... $450.7 $501.3 $779.9 $596.5 Operating Expenses and Taxes................ 389.4 423.1 658.6 522.1 - ------------------------------------------------------------------------------------------------------------- Operating Income............................ 61.3 78.2 121.3 74.4 Other Income ............................... 2.8 2.2 1.2 1.5 Net Interest Charges........................ 24.1 23.0 21.8 22.1 - ------------------------------------------------------------------------------------------------------------- Net Income.................................. $ 40.0 $ 57.4 $100.7 $ 53.8 ============================================================================================================= Earnings on Common Stock.................... $ 39.2 $ 57.0 $103.5 $ 53.7 ============================================================================================================= Three Months Ended ------------------------------------ March 31, June 30, Sept. 30, Oct. 1-Nov. 6, Nov. 7-Dec. 31, 2001 2001 2001 2001 2001 - ---------------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues.......................... $461.7 $521.0 $672.2 $ 183.7 | $282.9 Operating Expenses and Taxes................ 388.2 451.7 554.0 151.9 | 239.2 - -------------------------------------------------------------------------------------------------------|-------------- Operating Income............................ 73.5 69.3 118.2 31.8 | 43.7 Other Income (Expense)...................... 1.2 2.3 (2.7) (177.7) | 1.2 Net Interest Charges........................ 23.3 25.6 24.3 8.3 | 14.8 - -------------------------------------------------------------------------------------------------------|-------------- Net Income (Loss)........................... $ 51.4 $ 46.0 $ 91.2 $(154.2) | $ 30.1 =======================================================================================================|============== Earnings (Loss) on Common Stock............. $ 50.0 $ 44.7 $ 89.8 $(154.5) | $ 29.3 ====================================================================================================================== 30
Report of Independent Accountants To the Stockholders and Board of Directors of Jersey Central Power & Light Company: In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of Jersey Central Power & Light Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended and the year ended December 31, 2000 (pre-merger) in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The consolidated financial statements of Jersey Central Power & Light Company and subsidiaries as of December 31, 2001 and for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger) were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financials statements in their report dated March 18, 2002. PricewaterhouseCoopers LLP Cleveland, Ohio February 28, 2003 31 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. Report of Previous Independent Public Accountants To the Stockholders and Board of Directors of Jersey Central Power & Light Company: We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Jersey Central Power & Light Company (a New Jersey corporation and wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2001 (post-merger), and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Jersey Central Power & Light Company and subsidiary as of December 31, 2000 and for each of the two years in the period ended December 31, 2000 (pre-merger), were audited by other auditors whose report dated January 31, 2001, expressed an unqualified opinion on those statements. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the 2001 financial statements referred to above present fairly, in all material respects, the financial position of Jersey Central Power & Light Company and subsidiaries as of December 31, 2001 (post-merger), and the results of their operations and their cash flows for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger), in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. 32 EX-21 32 jc_ex21-4.txt EX. 21-4 LIST OF SUBS - JCP&L Exhibit 21.4 JERSEY CENTRAL POWER & LIGHT COMPANY SUBSIDIARIES OF THE REGISTRANT AT DECEMBER 31, 2002 STATE OF NAME OF SUBSIDIARY BUSINESS ORGANIZATION ------------------ -------- ------------ JCP&L PREFERRED CAPITAL, INC. SPECIAL-PURPOSE FINANCE DELAWARE JCP&L CAPITAL, L.P. SPECIAL-PURPOSE FINANCE DELAWARE JCP&L TRANSITION FUNDING LLC SPECIAL-PURPOSE FINANCE DELAWARE Note: JCP&L, along with its affiliates Met-Ed and Penelec, collectively own all of the common stock of Saxton Nuclear Experimental Corporation, a Pennsylvania nonprofit corporation organized for nuclear experimental purposes which is now inactive. The carrying value of the owners' investment has been written down to a nominal value. EX-23 33 jc_ex23-3.txt EX. 23-3 PWC CONSENT - JCP&L EXHIBIT 23.3 JERSEY CENTRAL POWER & LIGHT COMPANY CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-88783) of Jersey Central Power & Light Company of our report dated February 28, 2003 relating to the consolidated financial statements, which appears in the Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 28, 2003 relating to the financial statement schedule, which appears in this Form 10-K. PricewaterhouseCoopers LLP Cleveland, Ohio March 24, 2003 EX-99 34 jc_ex99-3.txt EX. 99-3 CEO CERTIFICATION LETTER - ETC Exhibit 99.3 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Jersey Central Power & Light Company ("Company") on Form 10-K for the year ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Earl T. Carey, President of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/Earl T. Carey ----------------------------- Earl T. Carey President (Chief Executive Officer) March 24, 2003 EX-12 35 me_ex12-7.txt EX. 12-7 FIXED CHARGE RATIO - MET-ED EXHIBIT 12.7 Page 1 METROPOLITAN EDISON COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
Year Ended December 31, -------------------------------- Jan. 1- Nov. 7- Year Ended 1998 1999 2000 Nov. 6, 2001 Dec. 31, 2001 Dec. 31, 2002 ---------- --------- -------- ------------ ------------- ------------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items................... $ 57,720 $ 95,123 $ 81,895 $ 62,381 | $14,617 $ 63,224 Interest and other charges, before reduction for | amounts capitalized............................... 59,687 61,842 55,181 48,568 | 8,461 50,969 Provision for income taxes.......................... 37,423 61,396 44,088 39,449 | 10,905 44,372 Interest element of rentals charged to income (a)... 9,784 4,381 1,543 284 | (693) 515 -------- -------- -------- -------- | ------- -------- Earnings as defined............................... $164,614 $222,742 $182,707 $150,682 | $33,290 $159,080 ======== ======== ======== ======== | ======= ======== | FIXED CHARGES AS DEFINED IN REGULATION S-K: | Interest on long-term debt.......................... $ 42,493 $ 45,996 $ 37,886 $ 33,101 | $ 5,615 $ 40,774 Other interest expense.............................. 8,194 2,527 10,639 9,219 | 1,744 2,636 Subsidiary's preferred stock dividend requirements.. 9,000 13,319 6,656 6,248 | 1,102 7,559 Interest element of rentals charged to income (a)... 9,784 4,381 1,543 284 | (693) 515 -------- -------- -------- -------- | ------- -------- Fixed charges as defined.......................... $ 69,471 $ 66,223 $ 56,724 $ 48,852 | $ 7,768 $ 51,484 ======== ======== ======== ======== | ======= ======== | CONSOLIDATED RATIO OF EARNINGS TO FIXED | CHARGES............................................. 2.37 3.36 3.22 3.08 | 4.29 3.09 ==== ==== ==== ==== | ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
EXHIBIT 12.7 Page 2 METROPOLITAN EDISON COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
Year Ended December 31, -------------------------------- Jan. 1- Nov. 7- Year Ended 1998 1999 2000 Nov. 6, 2001 Dec. 31, 2001 Dec. 31, 2002 ---------- --------- -------- ------------ ------------- ------------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items.................. $ 57,720 $ 95,123 $ 81,895 $ 62,381 $14,617 $ 63,224 Interest and other charges, before reduction for amounts capitalized.......................... 59,687 61,842 55,181 48,568 8,461 50,969 Provision for income taxes......................... 37,423 61,396 44,088 39,449 10,905 44,372 Interest element of rentals charged to income (a).. 9,784 4,381 1,543 284 (693) 515 -------- -------- -------- -------- -------- -------- Earnings as defined.............................. $164,614 $222,742 $182,707 $150,682 $33,290 $159,080 ======== ======== ======== ======== ======= ======== FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS): Interest on long-term debt......................... $ 42,493 $ 45,996 $ 37,886 $ 33,101 $ 5,615 $ 40,774 Other interest expense............................. 8,194 2,527 10,639 9,219 1,744 2,636 Preferred stock dividend requirements.............. 9,483 13,319 6,656 6,248 1,102 7,559 Adjustments to preferred stock dividends to state on a pre-income tax basis.................. 313 43 -- -- -- -- Interest element of rentals charged to income (a).. 9,784 4,381 1,543 284 (693) 515 -------- -------- -------- -------- -------- -------- Fixed charges as defined plus preferred stock dividend requirements (pre-income tax basis)... $ 70,267 $ 66,266 $ 56,724 $ 48,852 $ 7,768 $ 51,484 ======== ======== ======== ======== ======= ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)............................. 2.34 3.36 3.22 3.08 4.29 3.09 ==== ==== ==== ==== ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
EX-13 36 me_ex13-6.txt EX. 13-6 ANNUAL REPORT - MET-ED EXHIBIT 13.6 METROPOLITAN EDISON COMPANY 2002 ANNUAL REPORT TO STOCKHOLDERS Metropolitan Edison Company (Met-Ed) is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the distribution and sale of electric energy in an area of approximately 3,300 square miles in eastern Pennsylvania. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 1.3 million. In August 2000, FirstEnergy entered into an agreement to merge with GPU, Inc., under which FirstEnergy would acquire all of the outstanding shares of GPU, Inc.'s common stock for approximately $4.5 billion in cash and FirstEnergy common stock. The merger became effective on November 7, 2001 and is being accounted for by the purchase method. Prior to that time, Metropolitan Edison Company was a wholly owned subsidiary of GPU, Inc. Contents Page - -------- ---- Selected Financial Data........................................... 1 Management's Discussion and Analysis.............................. 2-11 Consolidated Statements of Income................................. 12 Consolidated Balance Sheets....................................... 13 Consolidated Statements of Capitalization......................... 14 Consolidated Statements of Common Stockholder's Equity............ 15 Consolidated Statements of Preferred Stock........................ 15 Consolidated Statements of Cash Flows............................. 16 Consolidated Statements of Taxes.................................. 17 Notes to Consolidated Financial Statements........................ 18-30 Reports of Independent Accountants................................ 31-32 METROPOLITAN EDISON COMPANY SELECTED FINANCIAL DATA
Nov. 7 - Jan. 1 - Year Ended December 31, --------------------------------- 2002 Dec. 31, 2001 Nov. 6, 2001 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------- (Dollars in thousands) Operating Revenues..................... $ 986,608 $ 143,760 | $ 824,556 $ 842,333 $ 902,827 $ 919,594 =========== ========== | ============ =========== ========== ========== | Operating Income....................... $ 91,271 $ 17,367 | $ 102,247 $ 135,211 $ 154,774 $ 124,447 =========== ========== | =========== =========== ========== ========== | Income Before Extraordinary Item....... $ 63,224 $ 14,617 | $ 62,381 $ 81,895 $ 95,123 $ 57,720 =========== ========== | ============ =========== ========== ========== | Net Income............................. $ 63,224 $ 14,617 | $ 62,381 $ 81,895 $ 95,123 $ 50,915 =========== ========== | ============ =========== ========== ========== | Earnings on Common Stock............... $ 63,224 $ 14,617 | $ 62,381 $ 81,895 $ 94,515 $ 50,432 =========== ========== | ============ =========== ============ ========== | Total Assets........................... $ 3,564,805 $3,607,187 | $ 2,708,062 $2,747,059 $3,347,822 =========== ========== | =========== ========== ========== | | Capitalization: | Common Stockholder's Equity......... $ 1,315,586 $1,288,953 | $ 537,013 $ 501,417 $ 687,059 Cumulative Preferred Stock.......... -- -- | -- -- 12,056 Company-Obligated Mandatorily | Redeemable Preferred Securities... -- -- | -- -- 100,000 Company-Obligated Trust Preferred | Securities........................ 92,409 92,200 | 100,000 100,000 -- Long-Term Debt...................... 538,790 583,077 | 496,860 496,883 546,904 ----------- ---------- | ------------ ------------ ---------- Total Capitalization.............. $ 1,946,785 $1,964,230 | $1,133,873 $1,098,300 $1,346,019 =========== ========== | ========== ========== ========== | | Capitalization Ratios: | Common Stockholder's Equity......... 67.6% 65.6%| 47.4% 45.7% 51.1% Cumulative Preferred Stock.......... -- -- | -- -- 0.9 Company-Obligated Mandatorily | Redeemable Preferred Securities... -- -- | -- -- 7.4 Company-Obligated Trust Preferred | Securities.......................... 4.7 4.7 | 8.8 9.1 -- Long-Term Debt...................... 27.7 29.7 | 43.8 45.2 40.6 ----- ----- | ----- ----- ----- Total Capitalization.............. 100.0% 100.0%| 100.0% 100.0% 100.0% ===== ===== | ===== ===== ===== | | Transmission and Distribution | Kilowatt-Hour Deliveries (Millions): | Residential......................... 4,738 793 | 3,712 4,377 4,265 4,040 Commercial.......................... 3,991 652 | 3,203 3,699 3,488 3,321 Industrial.......................... 3,972 662 | 3,506 4,412 4,085 4,174 Other............................... 35 6 | 27 38 107 110 ------- ------- | ------- ------ ------ ------ Total Retail........................ 12,736 2,113 | 10,448 12,526 11,945 11,645 Total Wholesale..................... 840 195 | 1,067 2,120 4,597 1,249 ------ ------- | ------- ------ ------ ------ Total............................... 13,576 2,308 | 11,515 14,646 16,542 12,894 ====== ======= | ======= ====== ====== ====== | | Customers Served: | Residential......................... 448,334 442,763 | 436,573 430,746 425,431 Commercial.......................... 58,010 57,278 | 56,080 54,969 53,764 Industrial.......................... 1,936 1,961 | 1,967 2,073 2,090 Other............................... 728 819 | 810 1,057 1,063 ------- ------- | ------- ------- ------- Total............................... 509,008 502,821 | 495,430 488,845 482,348 ======= ======= | ======= ======= ======= 1
METROPOLITAN EDISON COMPANY Management's Discussion and Analysis of Results of Operations and Financial Condition This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Results of Operations Net income decreased by 17.9% to $63.2 million in 2002, compared to $77.0 million in 2001, due to the absence of deferral accounting for energy costs in 2002 (see Regulatory Matters.), higher regulatory asset amortization and general taxes. These increases were partially offset by an increase in operating revenues and a decrease in other operating costs. In 2001, net income decreased by 6.0% to $77.0 million, from $81.9 million in 2000. Results in 2001 were affected by higher purchased power and other operating costs, partially offset by increased operating revenues. Operating revenues increased $18.3 million in 2002, following a $126.0 million increase in 2001. The sources of changes in operating revenues during 2002 and 2001, as compared to the prior year, are summarized in the following table. Sources of Revenue Changes 2002 2001 ----------------------------------------------------------------------------- Increase (Decrease) (In millions) Increase in kilowatt-hour sales due to level of retail customers shopping for generation service...... $ 23.8 $142.6 Increase in other retail kilowatt-hour sales............ 31.1 8.2 Decrease in wholesale sales............................. (34.4) (9.4) All other changes....................................... (2.2) (15.4) ----------------------------------------------------------------------------- Net Increase in Operating Revenues...................... $ 18.3 $126.0 ============================================================================== Electric Sales In 2002, further reductions in the number of residential and commercial customers who received their power from alternate suppliers, and therefore returned to us as full service customers, resulted in increased operating revenues. During 2002, only 12.7% of total kilowatt-hours delivered were to shopping customers, whereas that percentage was 16.2% in 2001 and 42.5% in 2000. In addition to the higher revenues from returning shopping customers, warmer summer weather in 2002 contributed to an increase in retail sales, as did a slight increase in the number of residential and commercial customers. Partially offsetting these 2002 increases were lower sales to industrial customers due to a decline in economic conditions. Revenues from wholesale sales were lower in 2002 compared to 2001 due to a decrease in kilowatt-hours available for sale to other parties, as well as lower average prices for energy in 2002. In 2001, kilowatt-hour sales to wholesale customers also decreased; however, the decrease was partially offset by an increase in the average price for energy sold, compared to 2000. Changes in kilowatt-hour sales by customer class in 2002 and 2001 are summarized in the following table: Changes in Kilowatt-hour Sales 2002 2001 Increase (Decrease) Residential.................. 5.0% 2.9% Commercial................... 3.4% 4.2% Industrial................... (4.2)% (5.5)% -------------------------------------------------- Total Retail................. 1.5% 0.3% Wholesale.................... (33.4)% (40.5)% -------------------------------------------------- Total Sales.................. (1.7)% (5.6)% -------------------------------------------------- 2 Operating Expenses and Taxes Total operating expenses and taxes increased $46.6 million in 2002, after increasing $141.6 million in 2001, compared to the preceding year. In 2002, the majority of the change was attributed to increases in purchased power costs, regulatory asset amortization and general taxes, offset in part by a decrease in other operating costs. An increase in purchased power and other operating costs accounted for the majority of the increase in 2001. Purchased power costs increased $42.1 million in 2002, compared to the prior year. The increase was due primarily to energy costs of $40.2 million incurred in 2002 that otherwise would have been deferred absent a Pennsylvania Commonwealth Court decision (see Regulatory Matters). That increase was partially offset by a reduction in power purchased during 2002. In 2001, purchased power costs increased $91.2 million, compared to 2000. The higher costs resulted from increased quantities of power purchased through two-party agreements and the PJM Power Pool due to a large number of customers returning to us in 2001 after receiving their power from alternate suppliers in 2000, as well as higher average prices of power purchased under two-party agreements. Partially offsetting the increase was the effect of the Pennsylvania Public Utility Commission's (PPUC) June 2001 order that allowed us to defer, for future recovery from customers, energy costs in excess of our fixed generation tariff rates, retroactive to January 1, 2001, in connection with our provider of last resort (PLR) obligation (see Regulatory Matters). Other operating costs decreased $23.8 million in 2002, compared to the previous year. The decrease resulted principally from reduced uncollectible accounts expense, personnel reductions, the absence of employee severance costs accrued in 2001 and the absence of costs related to the use of portable generators at substations under a 2001 pilot program. Other operating costs increased $47.8 million in 2001, compared to 2000, primarily due to the absence of a pension curtailment gain associated with employees who were terminated when we sold our generating assets. This gain was realized in 2000 as a result of the PPUC's Phase II Order. Other operating costs also increased due to costs related to Voluntary Enhanced Retirement Programs offered in 2001 to certain bargaining unit employees. In 2002, the provision for depreciation and amortization increased $20.6 million, compared to the prior year, primarily due to an increase in amortization related to competitive transition charge (CTC) regulatory assets. A $20.4 million increase in general taxes in 2002, compared to the prior year, was the result of an increase in Pennsylvania gross receipts taxes. Other Income Other income increased $8.5 million in 2002, compared to the prior year, primarily due to increased contract work performed during 2002, as well as the absence of 2001 net losses on futures contracts and options, and the absence of a 2001 payment for a sustainable energy fund, which was made in accordance with the Stipulation of Settlement related to the FirstEnergy/GPU merger. In 2001, other income increased $11.9 million, compared to 2000. The 2001 increase was due primarily to higher CTC interest income and the absence of a 2000 write-down of regulatory assets for decommissioning of Three Mile Island Unit 2 (TMI-2), representing the net realized gain previously recorded on the accident-related portion of the TMI-2 decommissioning trust. Partially offsetting the 2001 increases was the charge for the sustainable energy fund discussed above. Net Interest Charges Net interest charges decreased $6.1 million in 2002, compared to the prior year, primarily due to reduced short-term borrowing levels and amortization of purchase accounting fair market value adjustments recorded in connection with the merger. An additional reduction was attributable to the redemption of $30 million of notes in the first quarter of 2002; however, those reductions were partially offset by increased interest on long-term debt due to the issuance of $100 million of notes in September 2001 and $50 million of notes in May 2002, which were used to refinance $30 million of notes in July 2002. In 2001, net interest charges increased $1.2 million, compared to 2000, due to the September 2001 issuance of senior notes. Capital Resources and Liquidity Changes in Cash Position As of December 31, 2002, we had $15.7 million of cash and cash equivalents compared with $25.3 million as of December 31, 2001. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash flows provided from operating activities totaled $101.9 million in 2002 and $30.1 million in 2001. The sources of these changes are as follows: 3 Operating Cash Flows 2002 2001 ---------------------------------------------------------- (in millions) Cash earnings (1)............... $186 $102 Working capital................. (84) (72) ----------------------------------------------------------- Total................... $102 $30 =========================================================== (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and major noncash charges. Cash Flows From Financing Activities In 2002, net cash used for financing activities of $54.0 million reflects redemptions of debt and $60.0 million in common stock dividend payments to FirstEnergy, as well as the issuance of unsecured notes. The following table provides details regarding new issues and redemptions during 2002: Securities Issued or Redeemed in 2002 -------------------------------------------------------- (in millions) New Issues Unsecured notes........................ $50 -------------------------------------------------------- Redemptions First Mortgage Bonds................... 60 -------------------------------------------------------- Short-term Borrowings, net source of cash... 16 -------------------------------------------------------- We had $88.3 million of short-term indebtedness on December 31, 2002, compared to $72.0 million on December 31, 2001. We may borrow from our affiliates on a short-term basis. We will not issue first mortgage bonds (FMBs) other than as collateral for senior notes, since our senior note indentures prohibit (subject to certain exceptions) us from issuing any debt which is senior to the senior notes. As of December 31, 2002, we had the capability to issue $74 million of additional senior notes based upon FMB collateral. We have no restrictions on the issuance of preferred stock. At the end of 2002, our common equity as a percentage of capitalization stood at 68% compared to 66% and 47% at the end of 2001 and 2000, respectively. In 2001 we experienced a significant increase in this ratio due to the allocation of the purchase price when we were acquired by FirstEnergy. Cash Flows From Investing Activities Cash used for investing activities totaled $57.5 million in 2002 and $68.2 million in 2001, and was used primarily for property additions to support the distribution of electricity in both periods. Our cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Over the next three years, we expect to meet our contractual obligations with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets. Less than 1-3 3-5 More than Contractual Obligations Total 1 Year Years Years 5 Years - ------------------------------------------------------------------------------ (in millions) Long-term debt....... $ 587 $ 60 $ 90 $202 $ 235 Short-term borrowings 88 88 -- -- -- Preferred stock (1).. 92 -- -- -- 92 Operating leases (2). 53 2 3 3 45 Purchases (3)........ 2,158 264 318 337 1,239 - --------------------------------------------------------------------------- Total............. $2,978 $414 $411 $542 $1,611 - --------------------------------------------------------------------------- (1) Subject to mandatory redemption (2) Operating lease payments are net of reimbursements from sublessees (see Note 3) (3) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing Our capital spending for the period 2003 through 2007 is expected to be about $288 million, of which approximately $53 million applies to 2003. 4 Following approval of the merger of FirstEnergy and GPU by the New Jersey Board of Public Utilities on September 26, 2001, Standard and Poor's adjusted our corporate credit rating from A/A-1 to BBB/A-2, and our senior secured debt rating from A+ to BBB+. The credit rating outlook of Standard & Poor's is stable. On February 22, 2002, Moody's changed its credit rating outlook from stable to negative based upon a decision by the Commonwealth Court of Pennsylvania to remand to the PPUC for reconsideration its decisions regarding rate relief, accounting deferrals and the mechanism for sharing merger savings rendered in connection with its approval of the FirstEnergy/GPU merger (see Regulatory Matters). On February 22, 2002, Moody's Investor Service changed its credit rating outlook for FirstEnergy from stable to negative. The change was based upon a decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania Public Utility Commission (PPUC) for reconsideration its decision on the mechanism for sharing merger savings and reversed the PPUC decisions regarding rate relief and accounting deferrals rendered in connection with its approval of the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed its outlook for FirstEnergy's credit ratings from stable to negative citing recent developments including: damage to the Davis-Besse reactor vessel head, the Pennsylvania Commonwealth Court decision, and deteriorating market conditions for some sales of FirstEnergy's remaining non-core assets. On July 31, 2002, Fitch revised its rating outlook for FirstEnergy to negative from stable. The revised outlook reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's judgment about NRG's financial ability to consummate the purchase of four power plants from FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while NRG's liquidity position added uncertainty to FirstEnergy's sale of power plants to NRG, its ratings would not be affected. S&P found FirstEnergy's cash flows sufficiently stable to support a continued (although delayed) program of debt and preferred stock redemption. S&P noted that it would continue to closely monitor FirstEnergy's progress on various initiatives. On January 21, 2003, S&P indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa (FirstEnergy's Argentina operations), which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining its current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the Jersey Central Power & Light Company rate case, successful hedging of its short power position, and continued capture of projected merger savings. While FirstEnergy anticipates being prepared to restart the Davis-Besse plant in the spring of 2003 the Nuclear Regulatory Commission (NRC) must authorize the unit's restart following a formal inspection process prior to its returning the unit to service. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt could put additional pressure on Met-Ed's credit ratings. Market Risk Information We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. Our Risk Policy Committee, comprised of FirstEnergy executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk We are exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. Most of our non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under Statement of Financial Accounting Standards (SFAS) 133. The change in the fair value of commodity derivative contracts related to energy production during 2002 is summarized in the following table: Increase (Decrease) in the Fair Value of Commodity Derivative Contracts
Non-Hedge Hedge Total --------- ----- ----- (In millions) Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2002................. $ 2.2 $ 0.1 $ 2.3 New contract value when entered............................. -- -- -- Additions/Increase in value of existing contracts........... 15.2 1.6 16.8 Settled contracts........................................... -- (1.6) (1.6) ------------------------------- Net Assets - Derivatives Contracts as of December 31, 2002 (1) $17.4 $ 0.1 $ 17.5 =============================== Impact of Changes in Commodity Derivative Contracts (2) Balance Sheet Effects: Regulatory Liability..................................... $ 15.2 $ -- $ 15.2
(1) Includes $17.0 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Represents the increase in value of existing contracts and settled contracts 5 Derivatives included on the Consolidated Balance Sheet as of December 31, 2002: Non-Hedge Hedge Total --------- ----- ----- (In millions) Current- Other Assets................... $ -- $0.1 $ 0.1 Non-Current- Other Deferred Charges......... 17.4 -- 17.4 ------ ---- ------ Net assets................... $17.4 $0.1 $17.5 ===== ==== ===== The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. We use these results in developing estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: Source of Information - Fair Value by Contract Year
2003 2004 2005 2006 Thereafter Total ---- ---- ---- ---- ---------- ----- (In millions) Prices based on external sources...... $0.5 $0.6 $1.5 $ -- $ -- $ 2.6 Prices based on models(1)............. -- -- -- 2.2 12.7 14.9 ------------------------------------------------------------------- Total(2).......................... $0.5 $0.6 $1.5 $2.2 $12.7 $17.5 ===================================================================
(1) Broker quote sheets. (2) Includes $17.0 million from an embedded option that is offset by a regulatory liability and does not affect earnings. We perform sensitivity analyses to estimate our exposure to the market risk of our commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2002. Interest Rate Risk Our exposure to fluctuations in market interest rates is reduced since our debt has fixed interest rates, as noted in the following table. Comparison of Carrying Value to Fair Value
There- Fair 2003 2004 2005 2006 2007 after Total Value - ------------------------------------------------------------------------------------------------------------------ (Dollars in millions) Assets Investments other than Cash and Cash Equivalents-Fixed Income.. -- -- -- -- -- $ 54 $ 54 $54 Average interest rate..... 4.6% 4.6% - ------------------------------------------------------------------------------------------------------------------ Liabilities - ------------------------------------------------------------------------------------------------------------------ Long-term Debt: Fixed rate................... $60 $40 $50 $151 $51 $235 $587 $598 Average interest rate .... 7.0% 6.3% 7.0% 5.9% 5.9% 7.6% 6.8% - ------------------------------------------------------------------------------------------------------------------ Preferred Stock.............. -- -- -- -- -- $ 92 $ 92 $100 Average dividend rate .... 7.4% 7.4% - ------------------------------------------------------------------------------------------------------------------
We are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. Changes in the market value of our nuclear decommissioning trust funds are recognized by making corresponding changes to the decommissioning liability, as described in Note 1 to the consolidated financial statements. Equity Price Risk Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $81 million and $91 million at December 31, 2002 and 2001, respectively. A hypothetical 10% decrease in 6 prices quoted by stock exchanges would result in an $8 million reduction in fair value at December 31, 2002. (See Note 1 - "Supplemental Cash Flows Information.") Outlook Our industry continues to transition to a more competitive environment. As of January 1, 1999, all of our customers could select alternative energy suppliers. We continue to deliver power to homes and businesses through our existing distribution system, which remains regulated. The PPUC authorized our rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. We have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as our PLR obligation. Regulatory assets are costs which regulatory agencies have authorized for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of our regulatory assets are expected to continue to be recovered under the provisions of the regulatory plans as discussed below. Our regulatory assets totaled $1.2 billion and $1.3 billion as of December 31, 2002 and 2001, respectively. Regulatory Matters Effective September 1, 2002, we assigned our provider of last resort (PLR) responsibility to our unregulated supply affiliate, FirstEnergy Solutions Corp. (FES), through a wholesale power sale agreement which expires in December 2003 and may be extended for each successive calendar year. Under the terms of the wholesale agreement, FES assumed the supply obligation, and the energy supply profit and loss risk, for the portion of power supply requirements that we do not self-supply under our non-utility generation (NUG) contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces our exposure to high wholesale power prices by providing power at or below the shopping credit for our uncommitted PLR energy costs during the term of the agreement to FES. We will continue to defer the cost differences between NUG contract rates and the rates reflected in our capped generation rates. In its February 21, 2002 decision on Petitions for Review regarding the June 2001 PPUC orders which approved the FirstEnergy/GPU merger and provided us deferral accounting treatment for energy costs, the Commonwealth Court of Pennsylvania affirmed the PPUC merger decision, remanding the decision to the PPUC only with respect to the issue of merger savings. The Court reversed the PPUC's decision regarding our PLR obligations, and denied us authority to defer for future recovery the difference between our wholesale power costs and the amount we collect from retail customers. We and the PPUC each filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court in March 2002, asking it to review the Commonwealth Court decision. In the first quarter of 2002, we established a $103.0 million reserve against our PLR deferred energy costs incurred prior to our acquisition by FirstEnergy. The reserve reflected the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. The reserve increased goodwill by an aggregate net of tax amount of $60.3 million. On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the Commonwealth Court's decision, which effectively affirmed the PPUC's order approving the merger between FirstEnergy and GPU, let stand the Commonwealth Court's denial of our request for PLR rate relief and remanded the merger savings issue back to the PPUC. FERC Regulatory Matters On December 19, 2002 the Federal Energy Regulatory Commission (FERC) granted unconditional Regional Transmission Organization status to PJM Interconnection, LLC (PJM). We are a transmission owner in PJM. Environmental Matters We have been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, 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, our proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. We have accrued liabilities aggregating approximately $0.2 million as of December 31, 2002. We do not believe environmental remediation costs will have a material adverse effect on our financial condition, cash flows or results of operations. 7 Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against us, the most significant of which are described below. We have a 50% ownership interest in TMI-2, which was damaged during a 1979 accident. As a result of the accident, claims for alleged personal injury against Met-Ed, Jersey Central Power & Light Company, Pennsylvania Electric Company and GPU (the defendants) had been filed in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by the defendants and dismissed the ten initial "test cases" which had been selected for a test case trial. In January 2002, the District Court granted our motion for summary judgment on the remaining 2,100 pending claims. In February 2002, the plaintiffs filed a notice of appeal of this decision (see Note 6 - Other Legal Proceedings). In December 2002, the Court of Appeals for the Third Circuit refused to hear the appeal, which effectively ended further legal action for those claims. Significant Accounting Policies We prepare our consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Our more significant accounting policies are described below. Purchase Accounting On November 7, 2001, the merger between FirstEnergy and GPU became effective, and we became a wholly owned subsidiary of FirstEnergy. The merger was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities were based primarily on estimates. The adjustments reflected in our records, which were finalized in the fourth quarter of 2002, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. As of December 31, 2002, we had recorded goodwill of approximately $885.8 million related to the merger. Regulatory Accounting We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded - $1.2 billion as of December 31, 2002. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. We continually monitor our derivative contracts to determine if our activities, expectations, intentions, assumptions and estimates remain valid. As part of our normal operations, we enter into commodity contracts which increase the impact of derivative accounting judgments. 8 Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, we reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000. Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. The market values of our pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002, plan assets have earned (11.3)%. Our pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, we will not be required to fund our pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to our 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. Our non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $18 million and $6 million, respectively - a total of $24 million in 2003 as compared to 2002. 9 Increase in Costs from Adverse Changes in Key Assumptions ----------------------------------------------------------------------------- Assumption Adverse Change Pension OPEB Total ----------------------------------------------------------------------------- (In millions) Discount rate................ Decrease by 0.25% $1.3 $0.8 $2.1 Long-term return on assets... Decrease by 0.25% 0.9 0.2 1.1 Health care trend rate....... Increase by 1% na 2.3 2.3 Long-Lived Assets In accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment were to occur, other than of a temporary nature, we would recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Recently Issued Accounting Standards Not Yet Implemented SFAS 143, "Accounting for Asset Retirement Obligations" In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize regulatory assets or liabilities if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. We have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143, asset retirement costs of $186 million will be recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $186 million. The asset retirement liability at the date of adoption will be $198 million. As of December 31, 2002, we had recorded decommissioning liabilities of $260 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that substantially all of our nuclear decommissioning costs will be recoverable through regulated rates. Therefore, we recognized a regulatory liability of $61 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $0.4 million increase to income, or $0.2 million net of tax. SFAS 146, "Accounting for costs Associated with Exit or Disposal Activities" This statement, which was issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time they are incurred rather than when management commits to a plan of exit or disposal. It also requires the use of fair value for the measurement of such liabilities. The new standard supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This new standard was effective for exit and disposal activities initiated after December 31, 2002. Since it is applied prospectively, there will be no impact upon adoption. However, SFAS 146 could change the timing and amount of costs recognized in connection with future exit or disposal activities. FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" 10 The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. We currently have transactions with entities in connection with the sale of preferred securities, which may fall within the scope of this interpretation, and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. We currently consolidate these entities and believe we will continue to consolidate following the adoption of FIN 46. 11 METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME
Nov 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 - --------------------------------------------------------------------------------------------------------------------- (In thousands) OPERATING REVENUES (Note 1)............................... $ 986,608 $ 143,760 | $ 824,556 $ 842,333 --------- --------- | --------- ---------- | OPERATING EXPENSES AND TAXES: | Fuel and purchased power (Note 1)...................... 604,305 83,275 | 478,954 471,070 Other operating costs (Note 1)......................... 115,371 16,122 | 123,094 91,456 --------- --------- | --------- ---------- Total operation and maintenance expenses............. 719,676 99,397 | 602,048 562,526 Provision for depreciation and amortization............ 81,419 8,903 | 51,867 68,695 General taxes.......................................... 66,795 6,509 | 39,845 42,623 Income taxes........................................... 27,447 11,584 | 28,549 33,278 --------- --------- | --------- ---------- Total operating expenses and taxes................... 895,337 126,393 | 722,309 707,122 --------- --------- | --------- ---------- | OPERATING INCOME.......................................... 91,271 17,367 | 102,247 135,211 | OTHER INCOME.............................................. 21,742 5,465 | 7,807 1,387 --------- --------- | --------- ---------- | INCOME BEFORE NET INTEREST CHARGES........................ 113,013 22,832 | 110,054 136,598 --------- --------- | --------- ---------- | NET INTEREST CHARGES: | Interest on long-term debt............................. 40,774 5,615 | 33,101 37,886 Allowance for borrowed funds used during | construction......................................... (470) 30 | (574) (477) Deferred interest...................................... (710) (276) | (321) -- Other interest expense ................................ 2,636 1,744 | 9,219 10,638 Subsidiary's preferred stock dividend requirements..... 7,559 1,102 | 6,248 6,656 --------- --------- | --------- ---------- Net interest charges................................. 49,789 8,215 | 47,673 54,703 --------- --------- | --------- ---------- | NET INCOME................................................ $ 63,224 $ 14,617 | $ 62,381 $ 81,895 ========= ========= | ========= ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 12
METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS
As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------ (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $1,620,613 $1,609,974 Less-Accumulated provision for depreciation.................................... 547,925 530,006 ---------- ---------- 1,072,688 1,079,968 Construction work in progress- Electric plant............................................................... 16,078 14,291 ---------- ----------- 1,088,766 1,094,259 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts........................................... 155,690 157,699 Long-term notes receivable from associated companies........................... 12,418 12,418 Other.......................................................................... 19,206 13,391 ---------- ---------- 187,314 183,508 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 15,685 25,274 Receivables- Customers (less accumulated provisions of $4,810,000 and $12,271,000 respectively, for uncollectible accounts)................................. 120,868 112,257 Associated companies......................................................... 23,219 8,718 Other........................................................................ 18,235 16,675 Prepayments and other.......................................................... 9,731 12,239 ---------- ---------- 187,738 175,163 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 1,179,125 1,320,412 Goodwill....................................................................... 885,832 784,443 Other.......................................................................... 36,030 49,402 ---------- ---------- 2,100,987 2,154,257 ---------- ---------- $3,564,805 $3,607,187 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity.................................................... $1,315,586 $1,288,953 Company - obligated trust preferred securities................................. 92,409 92,200 Long-term debt................................................................. 538,790 583,077 ---------- ---------- 1,946,785 1,964,230 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt............................................... 60,467 30,029 Short-term borrowings (Note 5)- Associated companies......................................................... 88,299 72,011 Accounts payable- Associated companies......................................................... 56,861 67,351 Other........................................................................ 28,583 36,750 Accrued taxes................................................................. 16,096 7,037 Accrued interest............................................................... 16,448 17,468 Other.......................................................................... 11,690 13,652 ---------- ---------- 278,444 244,298 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes.............................................. 316,757 300,438 Accumulated deferred investment tax credits.................................... 12,518 13,310 Power purchase contract loss liability......................................... 660,507 730,662 Nuclear fuel disposal costs.................................................... 37,541 36,906 Nuclear plant decommissioning costs............................................ 270,611 268,967 Other.......................................................................... 41,642 48,376 ---------- ---------- 1,339,576 1,398,659 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 3 and 6)................................................................. ---------- ---------- $3,564,805 $3,607,187 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. 13
METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------ (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, without par value, authorized 900,000 shares 859,500 shares outstanding........................................................ $1,297,784 $1,274,325 Accumulated other comprehensive income (Note 4E).................................... (39) 11 Retained earnings (Note 4A)......................................................... 17,841 14,617 ---------- ---------- Total common stockholder's equity................................................. 1,315,586 1,288,953 ---------- ---------- COMPANY OBLIGATED TRUST PREFERRED SECURITIES OF SUBSIDIARY TRUST (NOTE 4C): 7.35% due 2039.................................................................... 92,409 92,200 ---------- ---------- LONG-TERM DEBT (Note 4D): First mortgage bonds: 8.05% due 2002.................................................................... -- 30,000 6.60% due 2003.................................................................... 20,000 20,000 7.22% due 2003.................................................................... 40,000 40,000 9.10% due 2003.................................................................... -- 30,000 6.34% due 2004.................................................................... 40,000 40,000 6.77% due 2005.................................................................... 30,000 30,000 7.35% due 2005.................................................................... 20,000 20,000 6.36% due 2006.................................................................... 17,000 17,000 6.40% due 2006.................................................................... 33,000 33,000 6.00% due 2008.................................................................... 8,700 8,700 6.10% due 2021.................................................................... 28,500 28,500 8.60% due 2022.................................................................... 30,000 30,000 8.80% due 2022.................................................................... 30,000 30,000 6.97% due 2023.................................................................... 30,000 30,000 7.65% due 2023.................................................................... 30,000 30,000 8.15% due 2023.................................................................... 60,000 60,000 5.95% due 2027.................................................................... 13,690 13,690 ---------- ---------- Total first mortgage bonds...................................................... 430,890 490,890 Secured note: 5.72% due 2006.................................................................... 100,000 100,000 5.93% due 2007.................................................................... 50,000 -- ----------- ---------- Total Secured notes............................................................. 150,000 100,000 Unsecured note: 7.69% due 2039.................................................................... 5,968 5,997 Net unamortized premium on debt..................................................... 12,399 16,219 Long-term debt due within one year.................................................. (60,467) (30,029) ---------- ---------- Total long-term debt ........................................................... 538,790 583,077 ---------- ---------- TOTAL CAPITALIZATION................................................................... $1,946,785 $1,964,230 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 14
METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Common Stock Accumulated ----------------- Other Other Comprehensive Number Carrying Paid-In Comprehensive Retained Income of Shares Value Capital Income (Loss) Earnings ------------- --------- -------- ------- ------------- --------- (Dollars in thousands) Balance, January 1, 2000....................... 859,500 $ 66,273 $400,200 $21,363 $ 13,581 Net income.................................. $81,895 81,895 Net unrealized gain (loss) on investments... (21,295) (21,295) Minimum pension liability................... (4) (4) ------- Comprehensive income........................ 60,596 ------- Cash dividends on common stock.............. (25,000) - --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000..................... 859,500 66,273 400,200 64 70,476 Net income.................................. 62,381 62,381 Net unrealized gain (loss) on investments... 5 5 Net unrealized gain (loss) on derivative instruments............................... (174) (174) ------- Comprehensive income........................ 62,212 ------- Cash dividends on common stock.............. (65,000) - --------------------------------------------------------------------------------------------------------------------- Balance, November 6, 2001...................... 859,500 66,273 400,200 (105) 67,857 Purchase accounting fair value adjustment... 1,208,052 (400,200) 105 (67,857) - --------------------------------------------------------------------------------------------------------------------- Balance, November 7, 2001...................... 859,500 1,274,325 -- -- -- Net income.................................. 14,617 14,617 Net unrealized gain (loss) on investments... 22 22 Net unrealized gain (loss) on derivative instruments.............................. (11) (11) ------- Comprehensive income........................ 14,628 - --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001..................... 859,500 1,274,325 -- 11 14,617 Net income.................................. 63,224 63,224 Net unrealized gain (loss) on investments... 17 17 Net unrealized gain (loss) on derivative instruments............................... (67) (67) ------- Comprehensive income........................ $63,174 ------- Cash dividends on common stock.............. (60,000) Purchase accounting fair value adjustment... 23,459 - --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002..................... 859,500 $1,297,784 $ -- $ (39) $ 17,841 =====================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK Subject to Mandatory Redemption --------------------- Number Carrying of Shares Value --------- -------- (Dollars in thousands) Balance, January 1, 2000............ 4,000,000 $100,000 ============================================================== Balance, December 31, 2000.......... 4,000,000 100,000 ============================================================== Purchase accounting fair value adjustment.............. (7,800) -------------------------------------------------------------- Balance, December 31, 2001.......... 4,000,000 92,200 Amortization of fair market value adjustment.............. 209 -------------------------------------------------------------- Balance, December 31, 2002.......... 4,000,000 $ 92,409 ============================================================== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 15 METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 - ----------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 63,224 $ 14,617 | $ 62,381 $ 81,895 Adjustments to reconcile net income to net | cash from operating activities: | Provision for depreciation and amortization................ 81,419 8,903 | 51,867 68,695 Other amortization......................................... (2,528) 154 | 1,147 5,684 Impact of PPUC rate order, net............................. -- -- | -- (44,580) Deferred costs recoverable as regulatory assets............ (18,938) 1,045 | (91,182) (7,941) Deferred income taxes, net................................. 23,356 906 | 53,464 22,483 Investment tax credits, net................................ (792) (128) | (721) (851) Receivables................................................ (24,672) 10,213 | 33,714 33,348 Accounts payable........................................... (18,657) (4,339) | (60,868) (48,395) Other (Note 7)............................................. (538) 8,286 | (59,313) (25,896) --------- -------- | -------- -------- Net cash provided from (used for) operating activities... 101,874 39,657 | (9,511) 84,442 --------- -------- | -------- -------- | CASH FLOWS FROM FINANCING ACTIVITIES: | New Financing- | Long-term debt............................................. 49,750 -- | 99,500 -- Short-term borrowings, net................................. 16,288 -- | 51,400 46,600 Redemptions and Repayments- | Long-term debt............................................. (60,000) -- | -- (50,000) Short-term borrowings, net................................. -- (25,989) | -- -- Dividend Payments- | Common stock............................................... (60,000) -- | (65,000) (25,000) --------- --------- | -------- -------- Net cash provided from (used for) financing activities... (53,962) (25,989) | 85,900 (28,400) --------- -------- | -------- -------- | CASH FLOWS FROM INVESTING ACTIVITIES: | Property additions........................................... (44,533) (7,787) | (47,660) (58,481) Contributions to decommissioning trusts...................... -- -- | (7,113) (8,700) Sale of investments.......................................... -- -- | -- 3,519 Other........................................................ (12,968) (453) | (5,209) -- --------- -------- | -------- -------- Net cash provided from (used for) investing activities... (57,501) (8,240) | (59,982) (63,662) --------- -------- | -------- -------- | | Net increase (decrease) in cash and cash equivalents............ (9,589) 5,428 | 16,407 (7,620) Cash and cash equivalents at beginning of period................ 25,274 19,846 | 3,439 11,059 --------- ------- | -------- -------- Cash and cash equivalents at end of period...................... $ 15,685 $25,274 | $ 19,846 $ 3,439 ========= ======= | ======== ======== | SUPPLEMENTAL CASH FLOWS INFORMATION: | Cash Paid During the Year- | Interest (net of amounts capitalized)...................... $ 46,266 $ -- | $ 41,473 $ 47,451 ========= ======= | ======== ======== Income taxes (refund)...................................... $ 34,385 $(2,990) | $ 7,486 $ 45,534 ========= ======= | ======== ======== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 16
METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF TAXES
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 - ----------------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: Real and personal property...................................... $ 1,384 $ 5 | $ 1,236 $ 1,826 State gross receipts *.......................................... 56,043 5,730 | 31,353 35,288 Social security and unemployment................................ 1 (1) | 14 -- Other........................................................... 9,367 775 | 7,242 5,509 --------- --------- | -------- -------- Total general taxes...................................... $ 66,795 $ 6,509 | $ 39,845 $ 42,623 ========= ========= | ======== ======== | PROVISION FOR INCOME TAXES: | Currently payable- | Federal...................................................... $ 15,371 $ 7,693 | $(11,534) $ 17,080 State........................................................ 6,437 2,433 | (1,760) 5,377 --------- --------- | -------- -------- 21,808 10,126 | (13,294) 22,457 --------- --------- | -------- -------- Deferred, net- | Federal...................................................... 19,615 934 | 41,297 19,476 State........................................................ 3,741 (28) | 12,167 3,007 --------- ---------- | --------- -------- 23,356 906 | 53,464 22,483 --------- --------- | -------- -------- Investment tax credit amortization.............................. (792) (128) | (721) (851) --------- --------- | -------- -------- Total provision for income taxes......................... $ 44,372 $ 10,904 | $ 39,449 $ 44,089 ========= ========== | ======== ======== | INCOME STATEMENT CLASSIFICATION | OF PROVISION FOR INCOME TAXES: | Operating income................................................ $ 27,447 $ 11,584 | $ 28,549 $ 33,278 Other income.................................................... 16,925 (680) | 10,900 10,811 ---------- --------- | -------- -------- Total provision for income taxes......................... $ 44,372 $ 10,904 | $ 39,449 $ 44,089 ========= ========= | ======== ======== | RECONCILIATION OF FEDERAL INCOME TAX | EXPENSE AT STATUTORY RATE TO TOTAL | PROVISION FOR INCOME TAXES: | Book income before provision for income taxes................... $107,596 $ 25,521 | $101,831 $125,983 ========= ========= | ======== ======== Federal income tax expense at statutory rate.................... $ 37,659 $ 8,932 | $ 35,641 $ 44,094 Increases (reductions) in taxes resulting from- | Amortization of investment tax credits....................... (792) (128) | (721) (851) Depreciation................................................. 1,362 304 | 926 300 State income tax, net of federal benefit..................... 6,107 938 | 7,388 7,379 Allocated share of consolidated tax savings.................. -- -- | (3,151) -- Other, net................................................... 36 858 | (634) (6,833) --------- --------- | -------- -------- Total provision for income taxes......................... $ 44,372 $ 10,904 | $ 39,449 $ 44,089 ========= ========= | ======== ======== | ACCUMULATED DEFERRED INCOME TAXES AT | DECEMBER 31: | Property basis differences...................................... $ 217,351 $ 211,394 | $203,352 Nuclear decommissioning......................................... (4,247) (5,623) | (9,797) Deferred sale and leaseback costs............................... (11,366) (12,077) | (11,298) Non-utility generation costs.................................... (4,832) 36,099 | 12,238 Purchase accounting basis difference............................ (642) (37,143) | -- Sale of generation assets....................................... (1,419) (1,420) | (1,397) Regulatory transition charge.................................... 88,315 85,414 | 69,828 Customer receivables for future income taxes.................... 50,259 49,755 | 51,247 Other........................................................... (16,662) (25,961) | (35,164) --------- --------- | -------- Net deferred income tax liability........................ $ 316,757 $ 300,438 | $279,009 ========= ========= | ======== * Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include Metropolitan Edison Company (Company) and its wholly owned subsidiaries. All significant intercompany transactions have been eliminated. The Company is a wholly owned subsidiary of FirstEnergy Corp. FirstEnergy also holds directly all of the issued and outstanding common shares of Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L) and Pennsylvania Electric Company (Penelec). The Company, JCP&L and Penelec were formerly wholly owned subsidiaries of GPU, Inc., which merged with FirstEnergy on November 7, 2001. Pre-merger period and post-merger period financial results are separated by a heavy black line. The Company follows the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Certain prior year amounts have been reclassified to conform with the current year presentation. (A) CONSOLIDATION- The Company consolidates all majority-owned subsidiaries, after eliminating the effects of intercompany transactions. Non-majority owned investments, including investments in limited liability companies, partnerships and joint ventures, are accounted for under the equity method when the Company is able to influence their financial or operating policies. Investments in corporations resulting in voting control of 20% or more are presumed to be equity method investments. Limited partnerships are evaluated in accordance with SEC Staff D-46, "Accounting for Limited Partnership Investments" and American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence. For all remaining investments (excluding those within the scope of Statement of Financial Accounting Standards (SFAS) 115, the Company applies the cost method. (B) REVENUES- The Company's principal business is providing electric service to customers in Pennsylvania. The Company's retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service provided through the end of the year. See Note 7 - Other Information for discussion of reporting of independent system operator transactions. Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2002 or 2001, with respect to any particular segment of the Company's customers. (C) REGULATORY PLAN- Pennsylvania enacted its electric utility competition law in 1996 with the phase-in of customer choice for generation suppliers completed as of January 1, 2001. In 1998, the PPUC authorized a rate restructuring plan for the Company which essentially resulted in the deregulation of the Company's generation business. The Company has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as the Company's provider of last resort (PLR) obligation. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in the Company's 1998 rate restructuring plan order. The PPUC required the Company to seek an Internal Revenue Service (IRS) ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. If the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to the Company's net income since the contingency existed prior to the Company being acquired by FirstEnergy. As a result of its generating asset divestitures, the Company obtained its supply of electricity to meet its PLR obligation almost entirely from contracted and open market purchases. In 2000, the Company filed a petition with the PPUC seeking permission to defer, for future recovery, energy costs in excess of amounts reflected in its capped generation rates; the PPUC subsequently consolidated this petition in January 2001 with the FirstEnergy/GPU merger proceeding (see Note 2 - Merger). 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 the Company PLR rate relief. 18 The PPUC permitted the Company to defer, for future recovery, the difference between its actual energy costs and those reflected in its capped generation rates, retroactive to January 1, 2001. Correspondingly, in the event that energy costs incurred by the Company were below its capped generation rates, that difference would have reduced costs that had been deferred for recovery in future periods. However, this PLR deferral accounting procedure was subsequently denied in a court decision, as discussed below. The Company's PLR obligation extends through December 31, 2010. Had the PLR accounting procedure been allowed, competitive transition charge (CTC) revenues would have been applied to the Company's PLR stranded costs during that period. The Company 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 Company's PLR obligation, and rejected those parts of the settlement that permitted the Company to defer for accounting purposes the difference between its wholesale power costs and the amount that it collects from retail customers. The Company 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/GPU merger with the Pennsylvania Supreme Court. In the first quarter of 2002, the Company established a $103.0 million reserve for its PLR deferred energy costs incurred prior to its acquisition by FirstEnergy. The reserve reflected the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. The reserve increased goodwill by an aggregate net of tax amount of $60.3 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 the Company and remanded the merger savings issue back to the PPUC. Effective September 1, 2002, the Company assigned its PLR responsibility to FES 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 the Company under its non-utility generation (NUG) contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces the Company's exposure to high wholesale power prices by providing power at or below the shopping credit for its uncommitted PLR energy costs during the term of the agreement with FES. The Company is authorized to continue deferring differences between NUG contract costs and amounts recovered through its capped generation rates. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," was discontinued in 1998 with respect to the Company's generation operations. The Company subsequently divested substantially all of its generating assets. The SEC issued interpretive guidance regarding asset impairment measurement, concluding that any supplemental regulated cash flows such as a CTC should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued were $17 million as of December 31, 2002. (D) PROPERTY, PLANT AND EQUIPMENT- As a result of the merger, a portion of the Company's property, plant and equipment was adjusted to reflect fair value. The majority of the Company's property, plant and equipment continues to be reflected at original cost since such assets remain subject to rate regulation on a historical cost basis. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 3.0% in 2002, 3.0% in 2001 and 2.9% in 2000. Annual depreciation expense in 2002 included approximately $9.5 million for future decommissioning costs applicable to the Company's ownership in Unit 2 of the Three Mile Island Nuclear Plant (TMI-2), a demonstration nuclear reactor (Saxton Nuclear Experimental Facility) owned by a wholly owned subsidiary of the Company (in conjunction with JCP&L and Penelec) and decommissioning liabilities for its previously divested nuclear generating units. The Company's share of the future obligation to decommission these units is approximately $261.2 million in current dollars and (using a 4.0% escalation rate) approximately $417.2 million in future dollars. The estimated obligation and the escalation rate 19 were developed based on site specific studies. Decommissioning of the demonstration nuclear reactor is expected to be completed in 2003; payments for decommissioning of the nuclear generating units are expected to begin in 2014, when actual decommissioning work is expected to begin. The Company has recovered approximately $66.6 million for future decommissioning through its electric rates from customers through December 31, 2002. The Company has also recognized an estimated liability of approximately $3.7 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992. In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead, if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. The Company has identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143, asset retirement costs of $186 million will be recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $186 million. The asset retirement liability at the date of adoption will be $198 million. As of December 31, 2002, the Company had recorded decommissioning liabilities of $260 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that the Company's ultimate nuclear decommissioning costs will be tracked and recovered through regulated rates. Therefore, the Company recognized a regulatory liability of $61 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $0.4 million increase to income, or $0.2 million net of tax. The FASB approved SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using purchase accounting. The provisions of the new standard relating to the determination of goodwill and other intangible assets have been applied to the FirstEnergy/GPU merger, which was accounted for as a purchase transaction, and have not materially affected the accounting for this transaction. Under SFAS 142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill is tested for impairment at least on an annual basis - based on the results of the transition analysis and the 2002 annual analysis, no impairment of the Company's goodwill is required. (E) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 4B). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date, resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows: 2002 2001 2000 ----------------------------------------------------------------------------- Valuation assumptions: Expected option term (years) 8.1 8.3 7.6 Expected volatility......... 23.31% 23.45% 21.77% Expected dividend yield..... 4.36% 5.00% 6.68% Risk-free interest rate..... 4.60% 4.67% 5.28% Fair value per option......... $6.45 $4.97 $2.86 ---------------------------------------------------------------------------- 20 The effects of applying fair value accounting to the FirstEnergy's stock options would not materially effect the Company's net income. (F) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Results for the period January 1, 2001 through November 6, 2001 were included in the final consolidated federal income tax return of GPU, and results for the period November 7, 2001 through December 31, 2001 were included in FirstEnergy's 2001 consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Company recognizing the tax benefit for any tax losses or credits it contributed to the consolidated return. (G) RETIREMENT BENEFITS- Effective December 31, 2001, the Company's defined benefit pension plan was merged into FirstEnergy's defined benefit pension plan. FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all of the Company's full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. FirstEnergy uses the projected unit credit method for funding purposes. The assets of the pension plan consist primarily of common stocks, United States government bonds and corporate bonds. Costs for the year 2001 include the former GPU companies' pension and other postretirement benefit costs for the period November 7, 2001 through December 31, 2001. The Company provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company pays insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Company. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheet as of December 31: 21
Other Pension Benefits Postretirement Benefits ---------------- ----------------------- 2002 2001 2002 2001 - ----------------------------------------------------------------------------------------------------------- (In millions) Change in benefit obligation: Benefit obligation as of January 1......... $3,547.9 $1,506.1 $ 1,581.6 $ 752.0 Service cost............................... 58.8 34.9 28.5 18.3 Interest cost.............................. 249.3 133.3 113.6 64.4 Plan amendments............................ -- 3.6 (121.1) -- Actuarial loss............................. 268.0 123.1 440.4 73.3 Voluntary early retirement program......... -- -- -- 2.3 GPU acquisition............................ (11.8) 1,878.3 110.0 716.9 Benefits paid.............................. (245.8) (131.4) (83.0) (45.6) ------------------------------------------------------------------------------------------- Benefit obligation as of December 31....... 3,866.4 3,547.9 2,070.0 1,581.6 ------------------------------------------------------------------------------------------- Change in fair value of plan assets: Fair value of plan assets as of January 1.. 3,483.7 1,706.0 535.0 23.0 Actual return on plan assets............... (348.9) 8.1 (57.1) 12.7 Company contribution....................... -- -- 37.9 43.3 GPU acquisition............................ -- 1,901.0 -- 462.0 Benefits paid.............................. (245.8) (131.4) (42.5) (6.0) ------------------------------------------------------------------------------------------- Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0 ------------------------------------------------------------------------------------------- Funded status of plan...................... (977.4) (64.2) (1,596.7) (1,046.6) Unrecognized actuarial loss................ 1,185.8 222.8 751.6 212.8 Unrecognized prior service cost............ 78.5 87.9 (106.8) 17.7 Unrecognized net transition obligation..... -- -- 92.4 101.6 ------------------------------------------------------------------------------------------- Net amount recognized...................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) =========================================================================================== Consolidated Balance Sheets classification: Prepaid (accrued) benefit cost............. $ (548.6) $ 246.5 $ (859.5) $ (714.5) Intangible asset........................... 78.5 -- -- -- Accumulated other comprehensive loss....... 757.0 -- -- -- ------------------------------------------------------------------------------------------- Net amount recognized...................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) ============================================================================================ Assumptions used as of December 31: Discount rate.............................. 6.75% 7.25% 6.75% 7.25% Expected long-term return on plan assets... 9.00% 10.25% 9.00% 10.25% Rate of compensation increase.............. 3.50% 4.00% 3.50% 4.00% Net pension and other postretirement benefit costs for the two years ended December 31, 2002 were computed as follows: Other Pension Benefits Postretirement Benefits -------------------- ----------------------- 2002 2001 2002 2001 --------------------------------------------------------------------------------------------------- (In millions) Service cost........................... $ 58.8 $ 34.9 $ 28.5 $18.3 Interest cost.......................... 249.3 133.3 113.6 64.4 Expected return on plan assets......... (346.1) (204.8) (51.7) (9.9) Amortization of transition obligation (asset) -- (2.1) 9.2 9.2 Amortization of prior service cost..... 9.3 8.8 3.2 3.2 Recognized net actuarial loss (gain)... -- -- 11.2 4.9 Voluntary early retirement program..... -- 6.1 -- 2.3 --------------------------------------------------------------------------------------------------- Net periodic benefit cost (income)..... $ (28.7) $ (23.8) $114.0 $92.4 ===================================================================================================
The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. A significant portion of the services provided to the Company are from affiliates, GPU Service, Inc. (GPUS) and FirstEnergy Service Company (FECO) (see Note 1H). Therefore, substantially all of the employees are with GPUS which bills the Company for services rendered. See Note 7D for the Company's amount of net pension and other postretirement benefit costs reflected in its Consolidated Statements of Income. 22 (H) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily GPUS and FES. During the three years ended December 31, 2002, GPUS provided legal, accounting, financial and other services to the Company. The Company also entered into sale and purchase transactions with affiliates (JCP&L and Penelec) during the period. Effective September 1, 2002, the Company assigned its PLR responsibility to FES through a wholesale power sale agreement. See Note 7 for affiliated companies' transactions schedule. FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from its affiliates, GPUS and FECO, both subsidiaries of FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act (PUHCA). The vast majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas: the ratio of each company's amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers and other factors; and specific departmental charge ratios. Management believes that these allocation methods are reasonable. (I) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31: 2002 2001 - ----------------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value - ----------------------------------------------------------------------------- (In millions) Long-term debt.................... $587 $598 $597 $601 Preferred stock................... $ 92 $100 $100 $ 93 Investments other than cash and cash equivalents........... $156 $156 $159 $160 - ----------------------------------------------------------------------------- The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to the Company's ratings. Long-term debt and preferred stock subject to mandatory redemption were recognized at fair value in connection with the merger. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. The Company has no securities held for trading purposes. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "Investments other than cash and cash equivalents" in the table above) consist of equity securities, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized losses were approximately $0.4 million and interest and dividend income totaled approximately $4.7 million. On January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an amendment of FASB Statement No. 133." The adoption resulted in the recognition of derivative assets on the Consolidated Balance Sheet at January 1, 2001 in the amount of $13.0 million, with a substantially offsetting amount 23 recorded in Regulatory Assets of $12.2 million. As of January 1, 2001, a cumulative effect of accounting change was recognized as an expense in Other Income (Deductions), Net on the Consolidated Statement of Income in the amount of $0.1 million. The Company is exposed to financial risks resulting from the fluctuation of commodity prices, including electricity and natural gas. To manage the volatility relating to these exposures, the Company uses a variety of non-derivative and derivative instruments, including options and futures contracts. These derivatives are used principally for hedging purposes. The Company has a Risk Policy Committee, comprised of FirstEnergy executive officers, which exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. The Company uses derivatives to hedge the risk of price fluctuations. The Company's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The majority of the Company's forward commodity contracts are considered "normal purchases and sales," as defined by SFAS 133, and are therefore excluded from the scope of SFAS 138. The options and futures contracts determined to be within the scope of SFAS 133 are accounted for as cash flow hedges and expire on various dates through 2003. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. There is currently a net deferred loss of $67 thousand included in Accumulated Other Comprehensive Loss as of December 31, 2002 related to derivative hedging activity, which will be reclassified to earnings during the next twelve months as hedged transactions occur. (J) REGULATORY ASSETS- The Company recognizes, as regulatory assets, costs which the FERC and PPUC have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Company's regulatory plan. The Company continues to bill and collect cost-based rates for its transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2002 2001 ----------------------------------------------------------------------- (In millions) Regulatory transition charge................... $ 986.2 $1,115.9 Customer receivables for future income taxes... 116.0 110.9 Nuclear decommissioning costs.................. 53.7 34.7 Provider of last resort deferrals.............. -- 32.7 Employee postretirement benefit costs.......... 19.5 21.4 Loss on reacquired debt........................ 4.4 4.8 Other.......................................... (0.7) -- ----------------------------------------------------------------------- Total....................................... $1,179.1 $1,320.4 ======================================================================= 2. MERGER: On November 7, 2001, the merger of FirstEnergy and GPU became effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000. As a result of the merger, GPU's former wholly owned subsidiaries, including the Company, became wholly owned subsidiaries of FirstEnergy. The merger was accounted for by the purchase method of accounting. The assets acquired and liabilities assumed were recorded at estimated fair values as determined by FirstEnergy's management based on information currently available and on current assumptions as to future operations. Merger purchase accounting adjustments recorded in the records of the Company primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. Other assets and liabilities were not adjusted since they remain subject to rate regulation on a historical cost basis. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. During 2002, certain pre-acquisition contingencies and other final adjustments to the fair values of the assets acquired and liabilities assumed were reflected in the final allocation of the purchase price. These adjustments primarily related to: (1) final actuarial calculations related to pension and postretirement benefit obligations; (2) establishment of a reserve for deferred energy costs recognized prior to the merger, and (3) return to accrual adjustments for income taxes. As a result of these adjustments, goodwill increased by approximately $101.4 million. As of December 31, 2002, the Company had recorded goodwill of approximately $885.8 million related to the merger. 24 3. LEASES: Consistent with regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Prior to the sale of its nuclear generating facility in December 1999, the Company's capital lease obligations related primarily to nuclear fuel lease agreements with nonaffiliated fuel trusts for the plant. The Company's most significant operating lease relates to the sale and leaseback of a portion of its ownership interest in the Merrill Creek Reservoir project. The interest element related to this lease was $0.2 million, $1.9 million and $1.9 million for the years 2002, 2001 and 2000. As of December 31, 2002, the future minimum lease payments on the Company's Merrill Creek operating lease, net of reimbursements from sublessees, are: $2.5 million, $1.2 million, $1.5 million, $1.5 million and $1.5 million for the years 2003 through 2007, respectively, and $45.2 million for the years thereafter. The Company's Merrill Creek lease payments were offset against the actual net divestiture proceeds received from the 1999 sales of its generating assets. 4. CAPITALIZATION: (A) RETAINED EARNINGS- The merger purchase accounting adjustments included resetting the retained earnings balance to zero at the November 7, 2001 merger date. In general, the Company's first mortgage bond (FMB) indentures restrict the payment of dividends or distributions on or with respect to the Company's common stock to amounts credited to earned surplus since approximately the date of its indenture. At such date, the Company had a balance of $3.4 million in its earned surplus account, which would not be available for dividends or other distributions. As of December 31, 2002, the Company had retained earnings available to pay common stock dividends of $14.5 million, net of amounts restricted under the Company's FMB indentures. (B) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 2002 2001 2000 --------------------------------------------------------------------- Restricted common shares granted...... 36,922 133,162 208,400 Weighted average market price ........ $36.04 $35.68 $26.63 Weighted average vesting period (years)............................. 3.2 3.7 3.8 Dividends restricted.................. Yes * Yes --------------------------------------------------------------------- * FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares 25 Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2002, there were 296,008 stock units outstanding. Stock option activities under the FE Programs for the past three years were as follows: Number of Weighted Average Stock Option Activities Options Exercise Price ------------------------------------------------------------------------- Balance, January 1, 2000......... 2,153,369 $25.32 (159,755 options exercisable).... 24.87 Options granted................ 3,011,584 23.24 Options exercised.............. 90,491 26.00 Options forfeited.............. 52,600 22.20 Balance, December 31, 2000...... 5,021,862 24.09 (473,314 options exercisable).... 24.11 Options granted................ 4,240,273 28.11 Options exercised.............. 694,403 24.24 Options forfeited.............. 120,044 28.07 Balance, December 31, 2001....... 8,447,688 26.04 (1,828,341 options exercisable).. 24.83 Options granted................ 3,399,579 34.48 Options exercised.............. 1,018,852 23.56 Options forfeited.............. 392,929 28.19 Balance, December 31, 2002...... 10,435,486 28.95 (1,400,206 options exercisable).. 26.07 As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 1E - Stock-Based Compensation. (C) PREFERRED AND PREFERENCE STOCK- The Company's preferred stock authorization consists of 10 million shares without par value. No preferred shares are currently outstanding. (D) COMPANY-OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY PARTNERSHIP PREFERRED SECURITIES- The Company has formed a statutory business trust, Met-Ed Capital Trust, which is owned through a wholly-owned limited partnership of the Company, Met-Ed Capital II, L.P., of which a wholly-owned subsidiary of the Company is the sole general partner. In this transaction, Met-Ed Capital Trust invested the gross proceeds from the sale of $100.0 million of its 7.35% trust preferred securities in the preferred securities of Met-Ed Capital II, L.P., which in turn invested those proceeds in $103.1 million of 7.35% subordinated debentures of the Company. The sole assets of Met-Ed Capital Trust are the preferred securities of Met-Ed Capital II, L.P., whose sole assets are the Company's subordinated debentures with the same rate and maturity date as the preferred securities. The Company has effectively provided a full and unconditional guarantee of its obligations under its trust's preferred securities. The trust preferred securities, which mature in 2039 and have a liquidation value of $25.00 per security, are redeemable at the option of the Company beginning in May 2004 at 100% of their principal amount. The interest on the subordinated debentures (and therefore the distributions on the preferred securities) may be deferred for up to 60 months, but the Company may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full. 26 (E) LONG-TERM DEBT- The Company's first mortgage bond indenture, which secures all of the Company's FMBs, serve as a direct first mortgage lien on substantially all of the Company's property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of these relate to the nonpayment of interest and/or principal on debt, which could trigger a default. Cross-default provisions also exist between FirstEnergy and the Company. Based on the amount of bonds authenticated by the Trustee through December 31, 2002 the Company's annual sinking and improvement fund requirements for all bonds issued under the mortgage amount to $5.9 million. The Company expects to fulfill its sinking and improvement fund obligation by providing refundable bonds to the Trustee. Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) ------------------------- 2003..........$ 60.5 2004.......... 40.5 2005.......... 50.5 2006.......... 150.5 2007.......... 50.5 ------------------------- The Company's obligations to repay certain pollution control revenue bonds are secured by several series of FMBs. Certain pollution control revenue bonds are entitled to the benefit of noncancelable municipal bond insurance policies of $42.2 million to pay principal of, or interest on, the pollution control revenue bonds. (F) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with the Company's parent. As of December 31, 2002, accumulated other comprehensive income consisted of an unrealized loss on derivative instruments of $39,000. 5. SHORT-TERM BORROWINGS: The Company may borrow from its affiliates on a short-term basis. As of December 31, 2002, the Company had total short-term borrowings of $88.3 million from its affiliates with a weighted average interest rate of approximately 1.8%. 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $288 million for property additions and improvements from 2003 through 2007, of which approximately $53 million is applicable to 2003. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its present ownership interest in TMI-2, the Company is exempt from any potential assessment under the industry retrospective rating plan. The Company is also insured as to its interest in TMI-2 under a policy issued to the operating company for the plant. Under this policy, $150 million is provided for property damage and decontamination and decommissioning costs. Under this policy, the Company can be assessed a maximum of approximately $0.4 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at TMI-2 exceed the policy limits of the insurance in effect with respect to 27 that plant, to the extent a nuclear incident is determined not to be covered by the Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs. (C ) ENVIRONMENTAL MATTERS- The Company has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, 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 Company's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. The Company has accrued liabilities aggregating approximately $0.2 million as of December 31, 2002. The Company does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. (D) OTHER LEGAL PROCEEDINGS- Various lawsuits, claims and proceedings related to the Company's normal business operations are pending against the Company, the most significant of which is described below. The Company has a 50% ownership interest in TMI-2, which was damaged during a 1979 accident. As a result of the accident, claims for alleged personal injury were filed against the Company, JCP&L, Penelec and GPU (the defendants) in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by the defendants and dismissed the ten initial "test cases" which had been selected for a test case trial. In January 2002, the District Court granted the defendants' July 2001 motion for summary judgment on the remaining 2,100 pending claims. In February 2002, the plaintiffs filed a notice of appeal to the United States Court of Appeals for the Third Circuit. In December 2002, the Court of Appeals refused to hear the appeal, which effectively ended further legal action for those claims. 7. OTHER INFORMATION: The following represents the financial data which includes supplemental unaudited prior years' information as compared to consolidated financial statements and notes previously reported in 2001 and 2000. (A) CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2000 ---- ---- ---- ---- (In thousands) Other cash flows from operating activities: Accrued taxes............................... $ 9,059 $5,229 | $(18,960) $(15,207) All other................................... (9,597) 3,057 | (40,353) (10,689) -------- ------- | -------- -------- Other cash provided from (used for) operating activities.................... $ (538) $8,286 | $(59,313) $(25,896) ========= ====== | ======== =======
(B) REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS- The Company records purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." The aggregate purchase and sales transactions for the three years ended December 31, 2002, are summarized as follows: 28 Nov. 7-Dec. 31, Jan. 1-Nov. 6, 2002 2001 2001 2000 ------------------------------------------------------------------------ (In millions) Sales............. $ 9 $ 1 | $11 $49 Purchases......... 67 13 | 81 18 --------------------------------------------|--------------------------- The Company's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from the PJM ISO from power sales (as reflected in the table above) during periods when the Company had additional available power capacity. Revenues also include sales by the Company of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when the Company required additional power to meet its retail load requirements. (C) TRANSACTIONS WITH AFFILIATED COMPANIES- The primary affiliated companies transactions are as follows: Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2000 - ------------------------------------------------------------------------------ (In millions) Operating Revenues: Wholesale sales-affiliated companies... $ 18.6 $ 3.2 | $ 8.4 $20.0 | Operating Expenses: | Power purchased from FES............... 171.9 10.6 | -- -- GPU Service, Inc. support services..... 68.1 14.0 | 81.0 77.0 Power purchased from other affiliates.. 9.5 1.9 | 9.2 2.3 - ----------------------------------------------------------|------------------- (D) RETIREMENTS BENEFITS (1) Net pension and other postretirement benefit costs (income) for the three years ended December 31, 2002 are approximately as follows: Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2000 - ------------------------------------------------------------------------------ (In millions) Pension Benefits.................... $(10.7) $(3.2) | $(8.3) $(5.9) Other Postretirement Benefits....... 2.7 1.4 | 8.0 10.4 - -----------------------------------------------------------|------------------ (1) Includes estimated portion of benefit costs included in billings from GPUS. 8. RECENTLY ISSUED ACCOUNTING STANDARDS: FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Company does not believe that implementation of FIN 45 will be material but it will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. 29 The Company currently has transactions with entities in connection with the sale of preferred securities, which may fall within the scope of this interpretation, and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. The Company currently consolidates these entities and believes it will continue to consolidate following the adoption of FIN 46. 9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001. Three Months Ended ----------------------------------------- March 31, June 30, Sept. 30, Dec. 31, 2002 2002 2002 2002 - ------------------------------------------------------------------------------- (In millions) Operating Revenues.................. $245.8 $240.0 $281.5 $219.3 Operating Expenses and Taxes........ 212.3 216.8 267.9 198.3 - ------------------------------------------------------------------------------- Operating Income.................... 33.5 23.2 13.6 21.0 Other Income........................ 5.2 5.5 5.9 5.1 Net Interest Charges................ 12.1 12.7 12.4 12.6 - ------------------------------------------------------------------------------- Net Income.......................... $ 26.6 $ 16.0 $ 7.1 $ 13.5 ===============================================================================
Three Months Ended -------------------------------------- March 31, June 30, Sept. 30, Oct. 1-Nov. 6 Nov. 7-Dec. 31, 2001 2001 2001 2001 2001 - ------------------------------------------------------------------------------------------------------------------------ (In millions) Operating Revenues.......................... $221.0 $222.6 $283.5 $97.5 | $143.7 Operating Expenses and Taxes................ 196.6 197.9 248.3 79.5 | 126.4 - -------------------------------------------------------------------------------------------------------|---------------- Operating Income............................ 24.4 24.7 35.2 18.0 | 17.3 Other Income (Expense)...................... 4.7 5.3 2.6 (4.8) | 5.5 Net Interest Charges........................ 13.1 14.1 13.3 7.2 | 8.2 - -------------------------------------------------------------------------------------------------------|---------------- Net Income.................................. $ 16.0 $ 15.9 $ 24.5 $ 6.0 | $ 14.6 ========================================================================================================================
30 Report of Independent Accountants To the Stockholders and Board of Directors of Metropolitan Edison Company: In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of Metropolitan Edison Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended and the year ended December 31, 2000 (pre-merger) in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The consolidated financial statements of Metropolitan Edison Company and subsidiaries as of December 31, 2001 and for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger) were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financials statements in their report dated March 18, 2002. PricewaterhouseCoopers LLP Cleveland, Ohio February 28, 2003 31 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. Report of Previous Independent Public Accountants To the Stockholders and Board of Directors of Metropolitan Edison Company: We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Metropolitan Edison Company (a Pennsylvania corporation and wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2001 (post-merger), and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Metropolitan Edison Company and subsidiaries as of December 31, 2000 and for each of the two years in the period ended December 31, 2000 (pre-merger), were audited by other auditors whose report dated January 31, 2001, expressed an unqualified opinion on those statements. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the 2001 financial statements referred to above present fairly, in all material respects, the financial position of Metropolitan Edison Company and subsidiaries as of December 31, 2001 (post-merger), and the results of their operations and their cash flows for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger), in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. 32 EX-21 37 me_ex21-5.txt EX. 21-5 LIST OF SUBS - MET-ED Exhibit 21.5 METROPOLITAN EDISON COMPANY SUBSIDIARIES OF THE REGISTRANT AT DECEMBER 31, 2002 STATE OF NAME OF SUBSIDIARY BUSINESS ORGANIZATION ------------------ -------- ------------ YORK HAVEN POWER COMPANY HYDROELECTRIC GENERATION NEW YORK MET-ED PREFERRED CAPITAL II, INC. SPECIAL-PURPOSE FINANCE DELAWARE MET-ED CAPITAL II, L.P. SPECIAL-PURPOSE FINANCE DELAWARE MET-ED CAPITAL TRUST SPECIAL-PURPOSE FINANCE DELAWARE Note: Met-Ed, along with its affiliates JCP&L and Penelec, collectively own all of the common stock of Saxton Nuclear Experimental Corporation, a Pennsylvania nonprofit corporation organized for nuclear experimental purposes which is now inactive. The carrying value of the owners' investment has been written down to a nominal value. EX-12 38 pn_ex12-8.txt EX. 12-8 FIXED CHARGE RATIO - PENELEC EXHIBIT 12.8 Page 1 PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
Year Ended December 31, ------------------------------- Jan. 1- Nov. 7 Year Ended 1998 1999 2000 Nov. 6, 2001 Dec. 31, 2001 Dec. 31, 2002 --------- --------- -------- ------------ ------------- ------------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items................... $ 58,590 $152,491 $ 39,250 $23,718 | $10,795 $ 50,910 Interest and other charges, before reduction | for amounts capitalized........................... 65,114 45,149 48,544 40,998 | 7,052 42,373 Provision for income taxes.......................... 42,537 54,383 29,754 19,402 | 8,231 34,248 Interest element of rentals charged to income (a)... 4,970 4,306 3,020 891 | 311 1,849 -------- -------- -------- ------- | ------- -------- Earnings as defined............................... $171,211 $256,329 $120,568 $85,009 | $26,389 $129,380 ======== ======== ======== ======= | ======= ======== | FIXED CHARGES AS DEFINED IN REGULATION S-K: | Interest on long-term debt.......................... $ 47,729 $ 31,837 $ 29,964 $28,751 | $ 3,972 $ 31,758 Other interest expense.............................. 8,197 4,359 11,546 6,008 | 1,979 3,061 Subsidiary's preferred stock dividend requirements.. 9,188 8,953 7,034 6,239 | 1,101 7,554 Interest element of rentals charged to income (a)... 4,970 4,306 3,020 891 | 311 1,849 -------- -------- -------- ------- | ------- -------- Fixed charges as defined.......................... $ 70,084 $ 49,455 $ 51,564 $41,889 | $ 7,363 $ 44,222 ======== ======== ======== ======= | ======= ======== | CONSOLIDATED RATIO OF EARNINGS TO FIXED | CHARGES............................................. 2.44 5.18 2.34 2.03 | 3.58 2.93 ==== ==== ==== ==== | ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
EXHIBIT 12.8 Page 2 PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
Year Ended December 31, ------------------------------- Jan. 1- Nov. 7 Year Ended 1998 1999 2000 Nov. 6, 2001 Dec. 31, 2001 Dec. 31, 2002 --------- --------- -------- ------------ ------------- ------------- (Dollars in Thousands) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items.................... $ 58,590 $152,491 $ 39,250 $23,718 | $10,795 $ 50,910 Interest and other charges, before reduction | for amounts capitalized............................ 65,114 45,149 48,544 40,998 | 7,052 42,373 Provision for income taxes........................... 42,537 54,383 29,754 19,402 | 8,231 34,248 Interest element of rentals charged to income (a).... 4,970 4,306 3,020 891 | 311 1,849 -------- -------- -------- ------- | ------- -------- Earnings as defined................................ $171,211 $256,329 $120,568 $85,009 | $26,389 $129,380 ======== ======== ======== ======= | ======= ======== | FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS | PREFERRED STOCK DIVIDEND REQUIREMENTS | (PRE-INCOME TAX BASIS): | Interest on long-term debt........................... $ 47,729 $ 31,837 $ 29,964 $28,751 | $ 3,972 $ 31,758 Other interest expense............................... 8,197 4,359 11,546 6,008 | 1,979 3,061 Preferred stock dividend requirements................ 9,883 9,107 7,034 6,239 | 1,101 7,554 Adjustments to preferred stock dividends to | state on a pre-income tax basis.................... 505 55 -- -- | -- -- Interest element of rentals charged to income (a).... 4,970 4,306 3,020 891 | 311 1,849 -------- -------- -------- ------- | ------- -------- Fixed charges as defined plus preferred stock | dividend requirements (pre-income tax basis)..... $ 71,284 $ 49,664 $ 51,564 $41,889 | $ 7,363 $ 44,222 ======== ======== ======== ======= | ======= ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES | PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS | (PRE-INCOME TAX BASIS)............................. 2.40 5.16 2.34 2.03 | 3.58 2.93 ==== ==== ==== ==== | ==== ==== - ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.
EX-13 39 pn_ex13-7.txt EX. 13-7 ANNUAL REPORT - PENELEC EXHIBIT 13.7 PENNSYLVANIA ELECTRIC COMPANY 2002 ANNUAL REPORT TO STOCKHOLDERS Pennsylvania Electric Company (Penelec) is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the distribution and sale of electric energy in an area of approximately 17,600 square miles in western Pennsylvania. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 1.6 million. The Company, as lessee of the property of the Waverly Electric Light & Power Company, also serves a population of about 13,400 in Waverly, New York and vicinity. In August 2000, FirstEnergy entered into an agreement to merge with GPU, Inc., under which FirstEnergy would acquire all of the outstanding shares of GPU, Inc.'s common stock for approximately $4.5 billion in cash and FirstEnergy common stock. The merger became effective on November 7, 2001 and is being accounted for by the purchase method. Prior to that time, Pennsylvania Electric Company was a wholly owned subsidiary of GPU, Inc. Contents Page - -------- ---- Selected Financial Data........................................... 1 Management's Discussion and Analysis.............................. 2-11 Consolidated Statements of Income................................. 12 Consolidated Balance Sheets....................................... 13 Consolidated Statements of Capitalization......................... 14 Consolidated Statements of Common Stockholder's Equity............ 15 Consolidated Statements of Preferred Stock........................ 15 Consolidated Statements of Cash Flows............................. 16 Consolidated Statements of Taxes.................................. 17 Notes to Consolidated Financial Statements........................ 18-30 Reports of Independent Accountants................................ 31-32 PENNSYLVANIA ELECTRIC COMPANY SELECTED FINANCIAL DATA
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 1999 1998 - ------------------------------------------------------------------------------------------------------------------------ (Dollars in thousands) Operating Revenues..................... $ 1,027,102 $ 140,062 $ 834,548 | $ 901,881 $ 921,965 $ 1,032,226 =========== =========== ===========| =========== ========== =========== | Operating Income....................... $ 88,190 $ 14,341 $ 70,049 | $ 80,336 $ 140,925 $ 125,623 =========== ========== =========== | =========== ========== =========== | Income Before Extraordinary Item....... $ 50,910 $ 10,795 $ 23,718 | $ 39,250 $ 152,491 $ 58,590 =========== ========== =========== | =========== ========== =========== | Net Income............................. $ 50,910 $ 10,795 $ 23,718 | $ 39,250 $ 152, 91$ $ 39,640 =========== =========== =========== | =========== =========== =========== | Earnings on Common Stock............... $ 50,910 $ 10,795 $ 23,718 | $ 39,250 $ 151,611 $ 38,945 =========== =========== =========== | =========== ========== =========== | Total Assets........................... $ 3,163,254 $ 3,300,269 | $ 2,331,484 $2,463,052 $ 3,565,747 =========== =========== | =========== ========== =========== | | Capitalization: | Common Stockholder's Equity......... $1,353,704 $1,306,576 | $ 469,837 $ 461,182 $ 767,304 Cumulative Preferred Stock.......... -- -- | -- -- 16,681 Company-Obligated Mandatorily | Redeemable Preferred Securities... -- -- | -- -- 105,000 Company-Obligated Trust Preferred | Securities........................ 92,214 92,000 | 100,000 100,000 -- Long-Term Debt...................... 470,274 472,400 | 519,481 426,795 629,027 ---------- ---------- | ---------- --------- ---------- Total Capitalization.............. $1,916,192 $1,870,976 | $1,089,318 $ 987,977 $1,518,012 ========== ========== | ========== ========= ========== | | Capitalization Ratios: | Common Stockholder's Equity......... 70.7% 69.8% | 43.1% 46.7% 50.5% Cumulative Preferred Stock......... -- -- | -- -- 1.1 Company-Obligated Mandatorily | Redeemable Preferred Securities... -- -- | -- -- 6.9 Company-Obligated Trust Preferred | Securities........................ 4.8 4.9 | 9.2 10.1 -- Long-Term Debt...................... 24.5 25.3 | 47.7 43.2 41.5 ------ ------ | ------ ------ ------ Total Capitalization.............. 100.0% 100.0% | 100.0% 100.0% 100.0% ===== ===== | ===== ===== ===== | | Transmission and Distribution | Kilowatt-Hour Deliveries (Millions): | Residential......................... 4,196 721 3,264 | 3,949 3,864 3,756 Commercial.......................... 4,753 758 3,733 | 4,509 4,319 4,198 Industrial.......................... 4,336 685 3,658 | 4,698 4,865 4,996 Other............................... 42 7 34 | 40 43 42 ------ ----- ----- | ------ ------ ------ Total Retail........................ 13,327 2,171 10,689 | 13,196 13,091 12,992 Total Wholesale..................... 516 107 1,351 | 2,885 4,219 4,309 ------ ----- ------ | ------ ------ ------ Total............................... 13,843 2,278 12,040 | 16,081 17,310 17,301 ====== ===== ====== | ====== ====== ====== | | Transmission and Distribution Deliveries | Customers Served: | Residential......................... 503,007 502,901 | 502,052 500,930 499,484 Commercial.......................... 77,125 76,005 | 74,282 73,979 73,014 Industrial.......................... 2,605 2,652 | 2,703 2,844 2,910 Other............................... 1,081 1,099 | 1,110 1,110 1,111 ------- ------- | ------- ------ ------ Total............................... 583,818 582,657 | 580,147 578,863 576,519 ======= ======= | ======= ======= ======= 1
PENNSYLVANIA ELECTRIC COMPANY Management's Discussion and Analysis of Results of Operations and Financial Condition This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Results of Operations Net income increased by 47.5% to $50.9 million in 2002, compared to $34.5 million in 2001, as a result of higher operating revenues and lower other operating costs. Partially offsetting these favorable results was the absence of deferral accounting for energy costs in 2002 (see Regulatory Matters), as well as higher general taxes. Net income decreased by 12.1% to $34.5 million in 2001 from $39.2 million in 2000. In 2001, earnings were negatively impacted by higher purchased power and other operating costs, as well as lower other income -- partially offset by increased operating revenues. Operating revenues increased $52.5 million in 2002, following a $72.7 million increase in 2001. The sources of the changes in operating revenues during 2002 and 2001, as compared to the prior year, are summarized in the following table. Sources of Revenue Changes 2002 2001 ------------------------------------------------------------- Increase (Decrease) (In millions) Increase in kilowatt-hour sales due to level of retail customers shopping for generation service...... $ 55.1 $134.5 Change in other retail kilowatt- hour sales........................... 43.8 (12.2) Decrease in wholesale sales............ (40.8) (50.6) All other changes...................... (5.6) 1.0 ------------------------------------------------------------- Net Increase in Operating Revenues..... $ 52.5 $ 72.7 ============================================================= Electric Sales In 2002, further reductions in the number of residential, commercial and industrial customers who received their power from alternate suppliers, and therefore returned to us as full service customers, resulted in increased operating revenues. During 2002, only 6.2% of total kilowatt-hours delivered were to shopping customers, whereas that percentage was 14.1% in 2001 and 37.3% in 2000. In addition to the higher revenues from returning shopping customers, warmer summer weather in 2002 contributed to an increase in retail sales, as did slight increases in the number of residential and commercial customers. A slight decrease in kilowatt-hour sales to industrial customers during 2002 was attributed to a decline in economic conditions. Due to a decrease in kilowatt-hours available for sale to other parties, as well as lower average prices for energy in 2002, revenues from wholesale sales were lower in 2002, as compared to 2001. Residential kilowatt-hour sales remained relatively flat, while commercial sales were slightly lower compared to 2000, primarily due to reduced customer usage. Industrial sales also decreased in 2001 compared to 2000 as a result of a decrease in the number of customers and lower usage by existing customers. Sales to wholesale customers also decreased in 2001 compared to 2000 due to a reduction in our available capacity. Changes in kilowatt-hour sales by customer class in 2002 and 2001 are summarized in the following table: Changes in Kilowatt-hour Sales 2002 2001 -------------------------------------------------- Increase (Decrease) Residential.................. 4.4% 0.9% Commercial................... 3.5% (0.4)% Industrial................... (1.8)% (7.6)% -------------------------------------------------- Total Retail................. 2.0% (2.5)% Wholesale.................... (64.7)% (49.5)% -------------------------------------------------- Total Sales.................. (4.8)% (11.0)% -------------------------------------------------- 2 Operating Expenses and Taxes Total operating expenses and taxes increased $48.7 million in 2002 and $68.7 million in 2001, compared to the preceding year. Increases in purchased power costs and general taxes, offset in part by a decrease in other operating costs, accounted for the majority of the increase in 2002. In 2001, the increase was due primarily to increases in purchased power and other operating costs. Purchased power costs increased $50.1 million in 2002, compared to the prior year. The increase was due primarily to energy costs of $32.8 million incurred in 2002 that otherwise would have been deferred absent a Pennsylvania Commonwealth Court decision (see Regulatory Matters). That increase was partially offset by a reduction in power purchased during 2002, as well as by the absence of a one-time $16.0 million pre-tax charge related to the termination of a wholesale energy contract with Allegheny Electric Cooperative in 2001. Purchased power costs increased $54.5 million in 2001, compared to 2000. The higher costs resulted from increased quantities of power purchased through the PJM Power Pool due to a large number of customers returning to us in 2001 after receiving their power from alternate suppliers in 2000, as well as higher average prices of power purchased under two-party agreements. Also included in the purchased power costs in 2001 was a $16.0 million pre-tax charge related to the termination of a wholesale energy contract discussed above. Offsetting these increases was the effect of the Pennsylvania Public Utility Commission's (PPUC) June 2001 order that allowed us to defer, for future rate recovery from customers, energy costs in excess of our fixed generation tariff rates, retroactive to January 1, 2001, in connection with our provider of last resort (PLR) obligation (see Regulatory Matters). Other operating costs decreased $25.6 million in 2002, compared to the previous year. The decrease was primarily due to reduced uncollectible accounts, personnel reductions and the absence of employee severance costs accrued in 2001. Other operating costs increased $9.9 million in 2001, compared to 2000, primarily due to the absence of a pension curtailment gain associated with employees who were terminated when we sold our generating assets. This gain was realized in 2000 as a result of the PPUC's Phase II Order. Other operating costs also increased due to costs related to Voluntary Enhanced Retirement Programs offered in 2001 to certain bargaining unit employees. General taxes increased $19.5 million in 2002, compared to the prior year, due primarily to an increase in Pennsylvania gross receipts taxes. Other Income Other income increased $5.3 million in 2002, compared to the prior year. The increase was primarily due to the absence of 2001 charges for a sustainable energy fund and renewable energy projects, which were required by the Stipulation of Settlement related to the FirstEnergy/GPU merger, and the absence of 2001 net losses on futures contracts and options. The increase was partially offset by a decrease in interest income. In 2001, other income decreased $10.3 million, compared to 2000, primarily due to charges for the sustainable energy fund and renewable energy projects discussed above, as well as lower interest income. Net Interest Charges Net interest charges decreased $7.3 million in 2002, compared to the previous year, due to reduced short-term borrowing levels and amortization of purchase accounting fair market value adjustments recorded in connection with the merger. Net interest charges decreased $1.5 million in 2001, compared to the prior year. The decrease was due to the absence of prior year expenses related to federal income taxes, higher deferred PLR interest costs, and lower short-term borrowing levels. These decreases were partially offset by interest expense on $93 million of senior notes issued during 2000. Capital Resources and Liquidity Changes in Cash Position As of December 31, 2002, we had $10.3 million of cash and cash equivalents compared with $39.0 million as of December 31, 2001. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash flows provided from operating activities totaled $39.3 million in 2002, and cash flows used for operating activities totaled $16.0 million in 2001. The sources of these changes are as follows: 3 Operating Cash Flows 2002 2001 ------------------------------------------ (In millions) Cash earnings (1)..... $ 97 $(21) Working capital....... (58) 5 ------------------------------------------ Total................. $ 39 $(16) ========================================== (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and major noncash charges. Cash Flows From Financing Activities In 2002, net cash used for financing activities of $66.2 million reflects redemptions of debt and $29.0 million in common stock dividends payments to FirstEnergy. The following table provides details regarding new issues and redemptions during 2002: Securities Issued or Redeemed in 2002 -------------------------------------------------- (In millions) Redemptions Unsecured notes........................... $50 -------------------------------------------------- Short-term Borrowings, net source of cash.... 13 In 2001, net cash provided from financing activities totaled $71.8 million, primarily due to a $50 million contribution from its former parent, GPU Inc. We had $90.4 million of short-term indebtedness on December 31, 2002, compared to $77.6 million on December 31, 2001. We may borrow from our affiliates on a short-term basis. We will not issue first mortgage bonds (FMB) other than as collateral for senior notes, since our senior note indentures prohibit (subject to certain exceptions) us from issuing any debt which is senior to the senior notes. As of December 31, 2002, we had the capability to issue $7 million of additional senior notes based upon FMB collateral. We have no restrictions on the issuance of preferred stock. At the end of 2002, our common equity as a percentage of capitalization stood at 71% compared to 70% and 43% at the end of 2001 and 2000, respectively. In 2001 we experienced a significant increase in this ratio due to the allocation of the purchase price in the merger between FirstEnergy and GPU. Cash Flows From Investing Activities Cash used for investing activities totaled $1.9 million in 2002 and cash used for investing activities totaled $17.4 million in 2001. In both periods, cash outflows for property additions to support the distribution of electricity were offset by proceeds from non-utility generation trusts. Our cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Over the next three years, we expect to meet our contractual obligations with cash flows from operations. Thereafter, we expect to use a combination of cash flows from operations and funds from the capital markets. Less than 1-3 3-5 More than Contractual Obligations Total 1 Year Years Years 5 Years - ------------------------------------------------------------------------------ (In millions) Long-term debt......... $ 469 $ -- $134 $ 3 $ 332 Short-term borrowings.. 90 90 -- -- -- Preferred stock (1).... 92 -- -- -- 92 Capital lease (2)...... 1 1 -- -- -- Purchases (3).......... 2,761 308 396 399 1,658 - ----------------------------------------------------------------------------- Total............... $3,413 $399 $530 $402 $2,082 - ----------------------------------------------------------------------------- (1) Subject to mandatory redemption (2) See note 3 (3) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing 4 Our capital spending for the period 2003-2007 is expected to be about $328 million, of which approximately $54 million applies to 2003. Following approval of the merger of FirstEnergy and GPU by the New Jersey Board of Public Utilities on September 26, 2001, Standard and Poor's adjusted our corporate credit rating from A/A-1 to BBB/A-2, and our senior secured debt rating from A+ to BBB+. The credit rating outlook of Standard & Poor's is stable. On February 22, 2002, Moody's changed its credit rating outlook from stable to negative based upon a decision by the Commonwealth Court of Pennsylvania to remand to the PPUC for reconsideration its decisions regarding rate relief, accounting deferrals and the mechanism for sharing merger savings rendered in connection with its approval of the FirstEnergy/GPU merger (see Regulatory Matters). On February 22, 2002, Moody's Investor Service changed its credit rating outlook for FirstEnergy from stable to negative. The change was based upon a decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania Public Utility Commission (PPUC) for reconsideration its decision on the mechanism for sharing merger savings and reversed the PPUC decisions regarding rate relief and accounting deferrals rendered in connection with its approval of the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed its outlook for FirstEnergy's credit ratings from stable to negative citing recent developments including: damage to the Davis-Besse reactor vessel head, the Pennsylvania Commonwealth Court decision, and deteriorating market conditions for some sales of FirstEnergy's remaining non-core assets. On July 31, 2002, Fitch revised its rating outlook for FirstEnergy to negative from stable. The revised outlook reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's judgment about NRG's financial ability to consummate the purchase of four power plants from FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while NRG's liquidity position added uncertainty to FirstEnergy's sale of power plants to NRG, its ratings would not be affected. S&P found FirstEnergy's cash flows sufficiently stable to support a continued (although delayed) program of debt and preferred stock redemption. S&P noted that it would continue to closely monitor FirstEnergy's progress on various initiatives. On January 21, 2003, S&P indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa (FirstEnergy's Argentina operations), which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining its current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. While FirstEnergy anticipates being prepared to restart the Davis-Besse plant in the spring of 2003 the Nuclear Regulatory Commission (NRC) must authorize the unit's restart following a formal inspection process prior to its returning the unit to service. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt could put additional pressure on Penelec's credit ratings. Market Risk Information We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. Our Risk Policy Committee, comprised of FirstEnergy executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk We are exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. Most of our non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under Statement of Financial Accounting Standards (SFAS) 133. The change in the fair value of commodity derivative contracts related to energy production during 2002 is summarized in the following table: 5 Increase (Decrease) in the Fair Value of Commodity Derivative Contracts
Non-Hedge Hedge Total --------- ----- ----- (In millions) Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2002................. $1.1 $ 0.2 $ 1.3 New contract value when entered............................. -- -- -- Additions/Increase in value of existing contracts........... 7.6 1.5 9.1 Settled contracts........................................... -- (1.6) (1.6) -------------------------------- Net Assets - Derivatives Contracts as of December 31, 2002 (1)..................................... $8.7 $ 0.1 $ 8.8 ================================ Impact of Changes in Commodity Derivative Contracts (2) Income Statement Effects (Pre-Tax).......................... $0.4 $ -- $ 0.4 Balance Sheet Effects: Other Comprehensive Income (Pre-Tax)..................... $ -- $(0.1) $(0.1) Regulatory Liability..................................... $7.2 $ -- $ 7.2
Derivatives included on the Consolidated Balance Sheet as of December 31, 2002: Non-Hedge Hedge Total --------- ----- ----- (In millions) Current- Other Assets................... $ -- $0.1 $0.1 Non-Current- Other Deferred Credits......... 8.7 -- 8.7 ---- ---- ---- Net assets................... $8.7 $0.1 $8.8 ==== ==== ==== (1) Includes $8.6 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Represents the increase in value of existing contracts and settled contracts. The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. We utilize these results in developing estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: Source of Information - Fair Value by Contract Year - --------------------------------------------------- 2003 2004 2005 2006 Thereafter Total ---- ---- ---- ---- ---------- ----- (In millions) Prices based on external sources(1).............. $0.3 $0.3 $0.8 $ -- $ - $1.4 Prices based on models.... -- -- -- 1.1 6.3 7.4 ------------------------------------------------- Total(2)............... $0.3 $0.3 $0.8 $1.1 $6.3 $8.8 ================================================= (1) Broker quote sheets. (2) Includes $8.6 million from an embedded option that is offset by a regulatory liability and does not affect earnings. We perform sensitivity analyses to estimate our exposure to the market risk of our commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2002. Interest Rate Risk Our exposure to fluctuations in market interest rates is reduced since our debt has fixed interest rates, as noted in the following table. 6
Comparison of Carrying Value to Fair Value - ------------------------------------------------------------------------------------------------------------------------ There- Fair 2003 2004 2005 2006 2007 after Total Value - ------------------------------------------------------------------------------------------------------------------------ (Dollars in millions) Assets Investments other than Cash and Cash Equivalents-Fixed Income.. -- -- -- -- -- $157 $157 $157 Average interest rate..... 4.5% 4.5% - ------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------ Liabilities - ------------------------------------------------------------------------------------------------------------------------ Long-term Debt: Fixed rate................... -- $126 $8 -- $3 $332 $469 $475 Average interest rate .... 5.8% 7.5% 6.1% 6.4% 6.3% - ------------------------------------------------------------------------------------------------------------------------ Preferred Stock.............. -- -- -- -- -- $ 92 $ 92 $100 Average dividend rate .... 7.3% 7.3% - ------------------------------------------------------------------------------------------------------------------------
We are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. Changes in the market value of our nuclear decommissioning trust funds are recognized by making corresponding changes to the decommissioning liability, as described in Note 1 to the consolidated financial statements. Equity Price Risk Included in nuclear decommissioning trusts, as required by the Nuclear Regulatory Commission, are marketable equity securities carried at their market value of approximately $42 million and $54 million at December 31, 2002 and 2001, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $4 million reduction in fair value at December 31, 2002. (See Note 1 - "Supplemental Cash Flows Information.") Outlook Our industry continues to transition to a more competitive environment. As of January 1, 1999, all of our customers could select alternative energy suppliers. We continue to deliver power to homes and businesses through our existing distribution system, which remains regulated. The PPUC authorized our rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a competitive transition charge (CTC). Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. We have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as our PLR obligation. Regulatory assets are costs which regulatory agencies have authorized for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of our regulatory assets are expected to continue to be recovered under the provisions of the regulatory plans as discussed below. Our regulatory assets totaled $600 million and $770 million as of December 31, 2002 and 2001, respectively. Regulatory Matters Effective September 1, 2002, we assigned our provider of last resort (PLR) responsibility obligation to our unregulated supply affiliate, FirstEnergy Solutions Corp. (FES), through a wholesale power sale agreement which expires in December 2003 and may be extended for each successive calendar year. Under the terms of the wholesale agreement, FES assumed the supply obligation, and the energy supply profit and loss risk, for the portion of power supply requirements that we do not self-supply under our non-utility generation (NUG) contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces our exposure to high wholesale power prices by providing power at or below the shopping credit for our uncommitted PLR energy costs during the term of the agreement to FES. We will continue to defer those cost differences between NUG contract rates and the rates reflected in our capped generation rates. In its February 21, 2002 decision on Petitions for Review regarding the June 2001 PPUC orders which approved the FirstEnergy/GPU merger and provided us deferral accounting treatment for energy costs, the Commonwealth Court of Pennsylvania affirmed the PPUC merger decision, remanding the decision to the PPUC only with respect to the issue of merger savings. The Court reversed the PPUC's decision regarding our PLR obligations, and denied us authority to defer for future recovery the difference between our wholesale power costs and the amount we collect from retail customers. We and the PPUC each filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court in March 2002, asking it to review the Commonwealth Court decision. In the first quarter of 2002, we established a $111.1 million reserve against our PLR deferred energy costs incurred prior to our acquisition by FirstEnergy. The reserve reflected the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. The reserve increased goodwill by an aggregate net of tax amount of 7 $65.0 million. On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the Commonwealth Court's decision, which effectively affirmed the PPUC's order approving the merger between FirstEnergy and GPU, let stand the Commonwealth Court's denial of our request for PLR rate relief and remanded the merger savings issue back to the PPUC. FERC Regulatory Matters On December 19, 2002 the Federal Energy Regulatory Commission (FERC) granted unconditional Regional Transmission Organization status to PJM Interconnection, LLC (PJM). We are a transmission owner in PJM. Environmental Matters We have been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, 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, our proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. We have total accrued liabilities aggregating approximately $0.3 million as of December 31, 2002. We do not believe environmental remediation costs will have a material adverse effect on our financial condition, cash flows or results of operations. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against us, the most significant of which are described below. We have a 25% ownership interest in Unit 2 of the Three Mile Island Nuclear Plant (TMI-2), which was damaged during a 1979 accident. As a result of the accident, claims for alleged personal injury against us, Jersey Central Power & Light Company, Metropolitan Edison Company and GPU (the defendants) had been filed in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by the defendants and dismissed the ten initial "test cases" which had been selected for a test case trial. In January 2002, the District Court granted our motion for summary judgment on the remaining 2,100 pending claims. In February 2002, the plaintiffs filed a notice of appeal of this decision (see Note 6 - Other Legal Proceedings). In December 2002, the Court of Appeals for the Third Circuit refused to hear the appeal, which effectively ended further legal action for those claims. Significant Accounting Policies We prepare our consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Our more significant accounting policies are described below. Purchase Accounting On November 7, 2001, the merger between FirstEnergy and GPU became effective, and we became a wholly owned subsidiary of FirstEnergy. The merger was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities were based primarily on estimates. The adjustments reflected in our records, which were finalized in the fourth quarter of 2002, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. As of December 31, 2002, we had recorded goodwill of approximately $898.1 million related to the merger. 8 Regulatory Accounting We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded - $599.7 million as of December 31, 2002. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. We continually monitor our derivative contracts to determine if our activities, expectations, intentions, assumptions and estimates remain valid. As part of our normal operations, we enter into commodity contracts which increase the impact of derivative accounting judgments. Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, we reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001 and 7.75% used in 2000. 9 Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. The market values of our pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 plan assets have earned (11.3)%. Our pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, we will not be required to fund our pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to our 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. Our non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $15 million and $5 million, respectively - a total of $20 million in 2003 as compared to 2002. Increase in Costs from Adverse Changes in Key Assumptions - ------------------------------------------------------------------------------ Assumption Adverse Change Pension OPEB Total (In millions) Discount rate................ Decrease by 0.25% $1.7 $1.1 $2.8 Long-term return on assets... Decrease by 0.25% 1.2 0.4 1.6 Health care trend rate....... Increase by 1% na 3.1 3.1 Long-Lived Assets In accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset, is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- SFAS 143, "Accounting for Asset Retirement Obligations" In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize regulatory assets or liabilities if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. We have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143, asset retirement costs of $93 million will be recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $93 million. The asset retirement liability at the date of adoption will be $99 million. As of December 31, 2002, we had recorded decommissioning liabilities of $130 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that substantially all of our nuclear decommissioning costs will be recoverable through regulated rates. Therefore, we recognized a regulatory liability of $29 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the 10 reversal of the previously recorded decommissioning liabilities was a $1.9 million increase to income, or $1.1 million net of tax. SFAS 146, "Accounting for costs Associated with Exit or Disposal Activities" This statement, which was issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time they are incurred rather than when management commits to a plan of exit or disposal. It also requires the use of fair value for the measurement of such liabilities. The new standard supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This new standard was effective for exit and disposal activities initiated after December 31, 2002. Since it is applied prospectively, there will be no impact upon adoption. However, SFAS 146 could change the timing and amount of costs recognized in connection with future exit or disposal activities. FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions beginning in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. We currently have involvement with entities in connection with the sale of preferred securities, which may fall within the scope of this interpretation, and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. We currently consolidate these entities and believe we will continue to consolidate following the adoption of FIN 46. 11 PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME
Nov 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 - ---------------------------------------------------------------------------------------------------------------------- (In thousands) OPERATING REVENUES........................................ $1,027,102 $140,062 | $834,548 $901,881 ---------- -------- | -------- -------- | OPERATING EXPENSES AND TAXES: | Fuel and purchased power............................... 649,725 79,815 | 519,838 545,117 Other operating costs.................................. 132,996 20,015 | 138,543 148,698 ---------- -------- | -------- -------- Total operation and maintenance expenses............. 782,721 99,830 | 658,381 693,815 Provision for depreciation and amortization............ 61,476 8,613 | 49,191 56,505 General taxes.......................................... 65,301 6,281 | 39,532 45,890 Income taxes........................................... 29,414 10,997 | 17,395 25,335 ---------- -------- | -------- -------- Total operating expenses and taxes................... 938,912 125,721 | 764,499 821,545 ---------- -------- | -------- -------- | OPERATING INCOME.......................................... 88,190 14,341 | 70,049 80,336 | OTHER INCOME (EXPENSE).................................... 1,742 3,049 | (6,610) 6,716 ---------- -------- | -------- -------- | INCOME BEFORE NET INTEREST CHARGES........................ 89,932 17,390 | 63,439 87,052 ---------- -------- | -------- -------- | NET INTEREST CHARGES: | Interest on long-term debt............................. 31,758 3,972 | 28,751 29,964 Allowance for borrowed funds used during | construction......................................... (52) 47 | (494) (742) Deferred interest ..................................... (3,299) (504) | (783) -- Other interest expense ................................ 3,061 1,979 | 6,008 11,546 Subsidiary's preferred stock dividend requirements..... 7,554 1,101 | 6,239 7,034 ---------- -------- | -------- -------- Net interest charges................................. 39,022 6,595 | 39,721 47,802 ---------- -------- | -------- -------- | NET INCOME................................................ $ 50,910 $ 10,795 | $ 23,718 $ 39,250 ========== ======== | ======== ======== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 12
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS
As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------ (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $1,844,999 $1,845,187 Less-Accumulated provision for depreciation.................................... 647,581 630,957 ---------- ---------- 1,197,418 1,214,230 Construction work in progress- Electric plant............................................................... 19,200 12,857 ----------- ---------- 1,216,618 1,227,087 OTHER PROPERTY AND INVESTMENTS: Non-utility generation trusts.................................................. 109,881 154,067 Nuclear plant decommissioning trusts........................................... 88,818 96,610 Long-term notes receivable from associated companies........................... 15,515 15,515 Other.......................................................................... 9,425 2,265 ---------- ---------- 223,639 268,457 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 10,310 39,033 Receivables- Customers (less accumulated provisions of $6,216,000 and $14,719,000 respectively, for uncollectible accounts).................................. 128,303 107,170 Associated companies......................................................... 45,236 40,203 Other........................................................................ 16,184 14,842 Prepayments and other.......................................................... 2,551 8,605 ---------- ---------- 202,584 209,853 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 599,663 769,807 Goodwill....................................................................... 898,086 797,362 Accumulated deferred income taxes.............................................. 1,517 -- Other.......................................................................... 21,147 27,703 ----------- ---------- 1,520,413 1,594,872 ---------- ---------- $3,163,254 $3,300,269 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity.................................................... $1,353,704 $1,306,576 Company-obligated trust preferred securities................................... 92,214 92,000 Long-term debt................................................................. 470,274 472,400 ---------- ---------- 1,916,192 1,870,976 CURRENT LIABILITIES: Currently payable long-term debt .............................................. 813 50,756 Short-term borrowings (Note 5)- Associated companies......................................................... 90,427 77,623 Accounts payable- Associated companies......................................................... 129,906 126,390 Other........................................................................ 29,690 38,720 Accrued taxes................................................................. 21,271 29,255 Accrued interest............................................................... 12,695 12,284 Other.......................................................................... 8,409 10,993 ---------- ---------- 293,211 346,021 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes.............................................. -- 21,682 Accumulated deferred investment tax credits.................................... 10,924 11,956 Nuclear plant decommissioning costs............................................ 135,450 135,483 Nuclear fuel disposal costs.................................................... 18,771 18,453 Power purchase contract loss liability......................................... 765,063 867,046 Other.......................................................................... 23,643 28,652 ----------- ---------- 953,851 1,083,272 COMMITMENTS AND CONTINGENCIES (Notes 3 and 6)................................................................ ---------- ---------- $3,163,254 $3,300,269 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. 13
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, par value $20 per share, authorized 5,400,000 shares 5,290,596 shares outstanding..................................................... $ 105,812 $ 105,812 Other paid-in capital.............................................................. 1,215,256 1,188,190 Accumulated other comprehensive income/(loss) (Note 4E)............................ (69) 1,779 Retained earnings (Note 4A)........................................................ 32,705 10,795 ----------- ----------- Total common stockholder's equity................................................ 1,353,704 1,306,576 ----------- ----------- Company obligated TRUST Preferred securities of subsidiary trust (NOTE 4C): 7.34% due 2039................................................................... 92,214 92,000 ----------- ----------- LONG-TERM DEBT (Note 4D): First mortgage bonds: 6.125% due 2007.................................................................. 3,905 4,110 5.35% due 2010................................................................... 12,310 12,310 5.35% due 2010................................................................... 12,000 12,000 5.80% due 2020................................................................... 20,000 20,000 6.05% due 2025................................................................... 25,000 25,000 ------------ ----------- Total first mortgage bonds..................................................... 73,215 73,420 ----------- ----------- Unsecured notes: 6.42% due 2002................................................................... -- 25,000 6.47% due 2002................................................................... -- 25,000 5.75% due 2004................................................................... 125,000 125,000 7.50% due 2005................................................................... 8,000 8,000 6.125% due 2009.................................................................. 100,000 100,000 7.77% due 2010................................................................... 35,000 35,000 6.625% due 2019.................................................................. 125,000 125,000 7.69% due 2039................................................................... 2,984 2,998 ----------- ----------- Total unsecured notes.......................................................... 395,984 445,998 ----------- ----------- Capital lease obligations (Note 3)................................................. 1,132 1,670 Net unamortized premium on debt.................................................... 756 2,068 Long-term debt due within one year................................................. (813) (50,756) ----------- ----------- Total long-term debt............................................................. 470,274 472,400 ----------- ----------- TOTAL CAPITALIZATION.................................................................. $ 1,916,192 $ 1,870,976 =========== =========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 14
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Common Stock Accumulated ------------ Other Other Comprehensive Number Par Paid-In Comprehensive Retained Income of Shares Value Capital Income (Loss) Earnings ------------- --------- ------- ---------- ------------ --------- (Dollars in thousands) Balance, January 1, 2000....................... 5,290,596 $105,812 $ 285,487 $ 10,619 $ 59,265 Net income.................................. $39,250 39,250 Net unrealized gain (loss) on investments... (10,596) (10,596) ------- Comprehensive income........................ 28,654 ======= Contributions from parent company........... 35,000 Cash dividends on common stock.............. (55,000) ------------------------------------------------------------------------------------------------------------ Balance, December 31, 2000..................... 5,290,596 105,812 320,487 23 43,515 Net income.................................. 23,718 23,718 Net unrealized gain on investments.......... 12 12 Net unrealized gain (loss) on derivative instruments............................... ( 1,064) (1,064) ------- Comprehensive income........................ 22,666 ======= Contributions from parent company........... 50,000 - --------------------------------------------------------------------------------------------------------------------- Balance, November 6, 2001...................... 5,290,596 105,812 370,487 (1,029) 67,233 Purchase accounting fair value adjustment... 817,703 1,029 67,233) - --------------------------------------------------------------------------------------------------------------------- Balance, November 7, 2001...................... 5,290,596 105,812 1,188,190 -- -- Net income.................................. 10,795 10,795 Net unrealized gain (loss) on investments... (2) (2) Net unrealized gain (loss) on derivative instruments............................... 1,781 1,781 ------- Comprehensive income........................ 12,574 ======= - --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001..................... 5,290,596 105,812 1,188,190 1,779 10,795 Net income.................................. 50,910 50,910 Net unrealized gain (loss) on investments... 5 5 Net unrealized gain (loss) on derivative instruments............................... (1,853) (1,853) -------- Comprehensive income........................ $49,062 ======= Cash dividends on common stock.............. (29,000) Purchase accounting fair value adjustment... 27,066 - --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002..................... 5,290,596 $105,812 $1,215,256 $ (69) $ 32,705 =====================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK Subject to Mandatory Redemption ------------------------- Number Carrying of Shares Value --------- -------- (Dollars in thousands) Balance, January 1, 2000.......... 4,000,000 $100,000 =============================================================== Balance, December 31, 2000........ 4,000,000 100,000 =============================================================== Purchase accounting fair value adjustment.............. (8,000) --------------------------------------------------------------- Balance, December 31, 2001........ 4,000,000 92,000 =============================================================== Amortization of fair market value adjustment.............. 214 --------------------------------------------------------------- Balance, December 31, 2002........ 4,000,000 $ 92,214 =============================================================== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 15 PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 - ---------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income........................................................ $ 50,910 $ 10,795 | $ 23,718 $ 39,250 Adjustments to reconcile net income to net | cash from operating activities: | Provision for depreciation and amortization.................. 61,476 8,613 | 49,191 56,505 Other amortization........................................... 94 309 | 1,672 347 Impact of PPUC rate order, net............................... -- -- | -- (21,550) Deferred costs recoverable as regulatory assets.............. (58,953) (7,467) | (143,462) (76,957) Deferred income taxes, net................................... 11,893 (23,127) | 60,170 15,946 Investment tax credits, net.................................. (1,032) (171) | (970) (1,142) Receivables.................................................. (27,509) (26,592) | 16,566 (19,089) Accounts payable............................................. (5,514) (19,382) | 29,462 (20,608) Other (Note 7)............................................... 7,947 41,590 | (36,884) (89,125) --------- -------- | --------- --------- Net cash provided from (used for) operating activities..... 39,312 (15,432) | (537) (116,423) --------- -------- | --------- --------- | CASH FLOWS FROM FINANCING ACTIVITIES: | New Financing- | Long-term debt............................................... -- -- | -- 118,000 Short-term borrowings, net................................... 12,804 2,623 | 19,200 2,200 Contributions from parent.................................... -- -- | 50,000 35,000 Redemptions and Repayments- | Long-term debt............................................... (49,973) -- | -- (25,000) Dividend Payments- | Common stock................................................. (29,000) -- | -- (55,000) --------- -------- | --------- --------- Net cash provided from (used for) financing activities..... (66,169) 2,623 | 69,200 75,200 --------- -------- | --------- --------- | CASH FLOWS FROM INVESTING ACTIVITIES: | Property additions............................................. (50,671) (9,687) | (50,543) (73,247) Proceeds from non-utility generation trusts.................... 49,044 29,944 | 18,339 75,991 Contributions to decommissioning trusts........................ -- -- | (15) (40) Other.......................................................... (239) (246) | (5,194) 6,617 --------- -------- | --------- --------- Net cash provided from (used for) investing activities..... (1,866) 20,011 | (37,413) 9,321 --------- -------- | --------- --------- | | Net increase (decrease) in cash and cash equivalents.............. (28,723) 7,202 | 31,250 (31,902) Cash and cash equivalents at beginning of period.................. 39,033 31,831 | 581 32,483 --------- -------- | --------- ---------- Cash and cash equivalents at end of period........................ $ 10,310 $ 39,033 | $ 31,831 $ 581 ========= ======== | ========= ========= | SUPPLEMENTAL CASH FLOWS INFORMATION: | Cash Paid During the Year- | Interest (net of amounts capitalized)........................ $ 32,695 $ 2,018 | $ 35,134 $ 33,409 ========= ========= | ========= ========= Income taxes (refund)........................................ $ 43,613 $(12,176) | $ (14,542) $ 110,395 ========= ======== | ========= ========= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 16
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF TAXES
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 - --------------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: Real and personal property...................................... $ 1,583 $ (146)| $ 1,622 $ 1,139 State gross receipts*........................................... 55,505 5,560 | 30,932 37,222 Other........................................................... 8,213 867 | 6,978 7,529 ----------- ------------ | --------- --------- Total general taxes...................................... $ 65,301 $ 6,281 | $ 39,532 $ 45,890 =========== ============ | ========= ========= | PROVISION FOR INCOME TAXES: | Currently payable- | Federal...................................................... $ 17,554 $ 23,861 | $ (36,615) $ 11,593 State........................................................ 5,833 7,667 | (3,183) 3,357 ------------ ------------ | --------- --------- 23,387 31,528 | (39,798) 14,950 ----------- ------------ | --------- --------- Deferred, net- | Federal...................................................... 10,600 (17,511)| 46,346 11,732 State........................................................ 1,293 (5,616)| 13,824 4,214 ----------- ------------ | --------- --------- 11,893 (23,127)| 60,170 15,946 ----------- ------------ | --------- --------- Investment tax credit amortization.............................. (1,032) (171)| (970) (1,142) ----------- ------------ | --------- --------- Total provision for income taxes......................... $ 34,248 $ 8,230 | $ 19,402 $ 29,754 =========== ============ | ========= ========= | INCOME STATEMENT CLASSIFICATION | OF PROVISION FOR INCOME TAXES: | Operating income................................................ $ 29,414 $ 10,997 | $ 17,395 $ 25,335 Other income.................................................... 4,834 (2,767)| 2,007 4,419 ----------- ------------ | --------- --------- Total provision for income taxes......................... $ 34,248 $ 8,230 | $ 19,402 $ 29,754 =========== ============ | ========= ========= | RECONCILIATION OF FEDERAL INCOME TAX | EXPENSE AT STATUTORY RATE TO TOTAL | PROVISION FOR INCOME TAXES: | Book income before provision for income taxes $ 85,158 $ 19,025 | $ 43,120 $ 69,004 =========== ============ | ========= ========= Federal income tax expense at statutory rate.................... $ 29,805 $ 6,659 | $ 15,092 $ 24,151 Increases (reductions) in taxes resulting from- | Amortization of investment tax credits....................... (1,032) (171)| (969) (1,140) Depreciation................................................. 1,591 555 | 1,407 1,183 State income tax, net of federal tax......................... 4,702 1,404 | 7,156 3,590 Allocated share of consolidated tax savings.................. -- -- | (2,912) -- Other, net................................................... (818) (217)| (372) 1,970 ----------- ------------ | --------- --------- Total provision for income taxes......................... $ 34,248 $ 8,230 | $ 19,402 $ 29,754 =========== ============ | ========= ========= | ACCUMULATED DEFERRED INCOME TAXES AT | DECEMBER 31: | Property basis differences...................................... $ 242,192 $ 256,951 | $ 250,410 Nuclear decommissioning......................................... (41,665) (42,138)| (35,495) Non-utility generation costs.................................... (223,644) (214,492)| (112,291) Purchase accounting basis difference............................ (762) (38,407)| -- Sale of generation assets....................................... 7,495 7,495 | 5,302 Regulatory transition charge.................................... -- 9,329 | (9,329) Customer receivables for future income taxes.................... 52,793 61,493 | 65,506 Other........................................................... (37,926) (18,549)| (139,090) ------------ ------------ | --------- Net deferred income tax liability (asset)................ $ (1,517) $ 21,682 | $ 25,013 ============ ============ | ========= * Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include Pennsylvania Electric Company (Company) and its wholly owned subsidiaries. All significant intercompany transactions have been eliminated. The Company is a wholly owned subsidiary of FirstEnergy Corp. FirstEnergy also holds directly all of the issued and outstanding common shares of Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L) and Metropolitan Edison Company (Met-Ed). The Company, JCP&L and Met-Ed were formerly wholly owned subsidiaries of GPU, Inc., which merged with FirstEnergy on November 7, 2001. Pre-merger and post-merger period financial results are separated by a heavy black line. The Company follows the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Certain prior year amounts have been reclassified to conform with the current year presentation. (A) CONSOLIDATION- The Company consolidates all majority-owned subsidiaries, after eliminating the effects of intercompany transactions. Non-majority owned investments, including investments in limited liability companies, partnerships and joint ventures, are accounted for under the equity method when the Company is able to influence their financial or operating policies. Investments in corporations resulting in voting control of 20% or more are presumed to be equity method investments. Limited partnerships are evaluated in accordance with SEC Staff D-46, "Accounting for Limited Partnership Investments" and American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence. For all remaining investments (excluding those within the scope of Statement of Financial Accounting Standards (SFAS) 115, the Company applies the cost method. (B) REVENUES- The Company's principal business is providing electric service to customers in Pennsylvania. The Company's retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service provided through the end of the year. See Note 7 - Other Information for discussion of reporting of independent system operator transactions. Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2002 or 2001, with respect to any particular segment of the Company's customers. (C) REGULATORY PLAN- Pennsylvania enacted its electric utility competition law in 1996 with the phase-in of customer choice for generation suppliers completed as of January 1, 2001. In 1998, the PPUC authorized a rate restructuring plan for the Company which essentially resulted in the deregulation of the Company's generation business. The Company has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as the Company's provider of last resort (PLR) obligation. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in the Company's 1998 rate restructuring plan order. The PPUC required the Company to seek an Internal Revenue Service (IRS) ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. If the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to the Company's net income since the contingency existed prior to the merger. As a result of its generating asset divestitures, the Company obtains its supply of electricity to meet its PLR obligation almost entirely from contracted and open market purchases. In 2000, the Company filed a petition with the PPUC seeking permission to defer, for future recovery, energy costs in excess of amounts reflected in its capped generation rates; the PPUC subsequently consolidated this petition in January 2001 with the FirstEnergy/GPU merger proceeding (see Note 2 - Merger). 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 the Company PLR rate relief. 18 The PPUC permitted the Company to defer, for future recovery, the difference between its actual energy costs and those reflected in its capped generation rates, retroactive to January 1, 2001. Correspondingly, in the event that energy costs incurred by the Company were below its capped generation rates, that difference would have reduced costs that had been deferred for recovery in future periods. However, this PLR deferral accounting procedure was subsequently denied in a court decision, as discussed below. The Company's PLR obligation extends through December 31, 2010. Had the PLR accounting procedure been allowed, competitive transition charge (CTC) revenues would have been applied to the Company's PLR stranded costs during that period. The Company 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 Company's PLR obligation, and rejected those parts of the settlement that permitted the Company to defer for accounting purposes the difference between its wholesale power costs and the amount that it collects from retail customers. The Company 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/GPU merger with the Pennsylvania Supreme Court. In the first quarter of 2002, the Company established a $111.1 million reserve for its PLR deferred energy costs incurred prior to its acquisition by FirstEnergy. The reserve reflected the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. The reserve increased goodwill by an aggregate net of tax amount of $65.0 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 the Company and remanded the merger savings issue back to the PPUC. Effective September 1, 2002, the Company assigned its PLR responsibility to FES 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 the Company under its non-utility generation (NUG) contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces the Company's exposure to high wholesale power prices by providing power at or below the shopping credit for its uncommitted PLR energy costs during the term of the agreement with FES. The Company is authorized to continue deferring differences between NUG contract costs and amounts recovered through its capped generation rates. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," was discontinued in 1998 with respect to the Company's generation operations. The Company subsequently divested substantially all of its generating assets. The SEC issued interpretive guidance regarding asset impairment measurement, concluding that any supplemental regulated cash flows such as a CTC should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. (D) PROPERTY, PLANT AND EQUIPMENT- As a result of the merger, a portion of the Company's property, plant and equipment was adjusted to reflect fair value. The majority of the Company's property, plant and equipment continues to be reflected at original cost since such assets remain subject to rate regulation on a historical cost basis. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 3.0% in 2002, 2.9% in 2001 and 2.7% in 2000. Annual depreciation expense in 2002 included approximately $0.3 million for future decommissioning costs applicable to the Company's ownership in Unit 2 of the Three Mile Island Nuclear Plant (TMI-2), a demonstration nuclear reactor (Saxton Nuclear Experimental Facility) owned by a wholly owned subsidiary of the Company (in conjunction with JCP&L and Met-Ed) and decommissioning liabilities for its previously divested nuclear generating units. The Company's share of the future obligation to decommission these units is approximately $131.2 million in current dollars and (using a 19 4.0% escalation rate) approximately $209.3 million in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Decommissioning of the demonstration nuclear reactor is expected to be completed in 2003; payments for decommissioning of the nuclear generating units are expected to begin in 2014, when actual decommissioning work is expected to begin. The Company has recovered approximately $50.2 million for future decommissioning through its electric rates from customers through December 31, 2002. The Company has also recognized an estimated liability of approximately $1.9 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992. In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead, if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. The Company has identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143, asset retirement costs of $93 million will be recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $93 million. The asset retirement liability at the date of adoption will be $99 million. As of December 31, 2002, the Company had recorded decommissioning liabilities of $130 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that the Company's ultimate nuclear decommissioning costs will be tracked and recovered through regulated rates. Therefore, the Company recognized a regulatory liability of $29 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The remaining cumulative effect adjustment to recognize the undepreciated asset retirement cost and the asset retirement liability offset by the reversal of the previously recorded decommissioning liabilities was a $1.9 million increase to income, or $1.1 million net of tax. The FASB approved SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using purchase accounting. The provisions of the new standard relating to the determination of goodwill and other intangible assets have been applied to the FirstEnergy/GPU merger, which was accounted for as a purchase transaction, and have not materially affected the accounting for this transaction. Under SFAS 142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill is tested for impairment at least on an annual basis - based on the results of the transition analysis and the 2002 annual analysis, no impairment of the Company's goodwill is required. (E) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 4B). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date, resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows: 20 2002 2001 2000 - ------------------------------------------------------------------------- Valuation assumptions: Expected option term (years)..... 8.1 8.3 7.6 Expected volatility 23.31% 23.45% 21.77% Expected dividend yield.......... 4.36% 5.00% 6.68% Risk-free interest rate.......... 4.60% 4.67% 5.28% Fair value per option.............. $6.45 $4.97 $2.86 ---------------------------------------------------------------- The effects of applying fair value accounting to the FirstEnergy's stock options would not materially effect the Company's net income. (F) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Results for the period January 1, 2001 through November 6, 2001 were included in the final consolidated federal income tax return of GPU, and results for the period November 7, 2001 through December 31, 2001 were included in FirstEnergy's 2001 consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Company recognizing the tax benefit for any tax losses or credits it contributed to the consolidated return. (G) RETIREMENT BENEFITS- Effective December 31, 2001, the Company's defined benefit pension plan was merged into FirstEnergy's defined benefit pension plan. FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all of the Company's full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. FirstEnergy uses the projected unit credit method for funding purposes. The assets of the pension plan consist primarily of common stocks, United States government bonds and corporate bonds. Costs for the year 2001 include the former GPU companies' pension and other postretirement benefit costs for the period November 7, 2001 through December 31, 2001. The Company provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company pays insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Company. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheet as of December 31: 21
Other Pension Benefits Postretirement Benefits ---------------- ----------------------- 2002 2001 2002 2001 -------------------------------------------------------------------------------------------------- (In millions) Change in benefit obligation: Benefit obligation as of January 1.......... $3,547.9 $1,506.1 $ 1,581.6 $ 752.0 Service cost................................ 58.8 34.9 28.5 18.3 Interest cost............................... 249.3 133.3 113.6 64.4 Plan amendments............................. -- 3.6 (121.1) -- Actuarial loss.............................. 268.0 123.1 440.4 73.3 Voluntary early retirement program.......... -- -- -- 2.3 GPU acquisition............................. (11.8) 1,878.3 110.0 716.9 Benefits paid............................... (245.8) (131.4) (83.0) (45.6) -------------------------------------------------------------------------------------------------- Benefit obligation as of December 31........ 3,866.4 3,547.9 2,070.0 1,581.6 -------------------------------------------------------------------------------------------------- Change in fair value of plan assets: Fair value of plan assets as of January 1... 3,483.7 1,706.0 535.0 23.0 Actual return on plan assets................ (348.9) 8.1 (57.1) 12.7 Company contribution........................ -- -- 37.9 43.3 GPU acquisition............................. -- 1,901.0 -- 462.0 Benefits paid............................... (245.8) (131.4) (42.5) (6.0) ------------------------------------------------------------------------------------------------- Fair value of plan assets as of December 31. 2,889.0 3,483.7 473.3 535.0 ------------------------------------------------------------------------------------------------- Funded status of plan....................... (977.4) (64.2) (1,596.7) (1,046.6) Unrecognized actuarial loss................. 1,185.8 222.8 751.6 212.8 Unrecognized prior service cost............. 78.5 87.9 (106.8) 17.7 Unrecognized net transition obligation...... -- -- 92.4 101.6 ------------------------------------------------------------------------------------------------- Net amount recognized....................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) ========================================================================================------=== Consolidated Balance Sheets classifications: Prepaid (accrued) benefit cost.............. $ (548.6) $ 246.5 $ (859.5) $ (714.5) Intangible asset............................ 78.5 -- -- -- Accumulated other comprehensive loss........ 757.0 -- -- -- -------------------------------------------------------------------------------------------------- Net amount recognized....................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) =======================================================================------===================== Assumptions used as of December 31: Discount rate............................... 6.75% 7.25% 6.75% 7.25% Expected long-term return on plan assets.... 9.00% 10.25% 9.00% 10.25% Rate of compensation increase............... 3.50% 4.00% 3.50% 4.00% Net pension and other postretirement benefit costs for the two years ended December 31, 2002 were computed as follows: Other Pension Benefits Postretirement Benefits ---------------------- ----------------------- 2002 2001 2002 2001 -------------------------------------------------------------------------------------------------- (In millions) Service cost........................... $ 58.8 $ 34.9 $ 28.5 $18.3 Interest cost.......................... 249.3 133.3 113.6 64.4 Expected return on plan assets......... (346.1) (204.8) (51.7) (9.9) Amortization of transition obligation (asset) -- (2.1) 9.2 9.2 Amortization of prior service cost..... 9.3 8.8 3.2 3.2 Recognized net actuarial loss (gain)... -- -- 11.2 4.9 Voluntary early retirement program..... -- 6.1 -- 2.3 -------------------------------------------------------------------------------------------------- Net periodic benefit cost (income)..... $ (28.7) $ (23.8) $114.0 $92.4 ==================================================================================================
The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. A significant portion of the services provided to the Company are from affiliates, GPU Service, Inc. (GPUS) and FirstEnergy Service Company (FECO) (see Note 1H). Therefore, substantially all of the employees are with GPUS which bills the Company for services rendered. See Note 7D for the Company's amount of net pension and other postretirement benefit costs reflected in its Consolidated Statements of Income. 22 (H) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily GPUS and FES. During the three years ended December 31, 2002, GPUS provided legal, accounting, financial and other services to the Company. The Company also entered into sale and purchase transactions with affiliates (JCP&L and Met-Ed) during the period. Effective September 1, 2002, the Company assigned its PLR responsibility to FES through a wholesale power sale agreement. FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from its affiliates, GPUS and FECO, both subsidiaries of FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act ("PUHCA"). The vast majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas; the ratio of each company's amount of the FirstEnergy's aggregate total for direct payroll, number of employees, asset balances, revenues, number of customers and other factors; and specific departmental charge ratios. It is management's belief that allocation methods utilized are reasonable. (I) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31: 2002 2001 - ---------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value -------- ----- -------- ----- (In millions) Long-term debt................ $469 $475 $519 $509 Preferred stock............... $ 92 $100 $ 92 $ 90 Investments other than cash and cash equivalents........ $199 $199 $251 $251 The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to the Company's ratings. Long-term debt and preferred stock subject to mandatory redemption were recognized at fair value in connection with the merger. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. The Company has no securities held for trading purposes. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "Investments other than cash and cash equivalents" in the table above) consist of equity securities, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized gains were approximately $0.2 million and interest and dividend income totaled approximately $2.7 million. On January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an 23 amendment of FASB Statement No. 133." The adoption resulted in the recognition of derivative assets on the Consolidated Balance Sheet as of January 1, 2001 in the amount of $26.0 million, with an offsetting amount, net of tax, recorded in Regulatory Assets of $25.9 million. As of January 1, 2001, the Company also recorded derivative liabilities in the amount of $1.0 million as a result of adopting SFAS 133, with a substantially offsetting amount recorded in Accumulated Other Comprehensive Income, of $0.5 million. As of January 1, 2001, a cumulative effect of accounting change was recognized as an expense in Other Income (Deductions), Net on the Consolidated Statement of Income in the amount of $0.8 million. The Company is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including electricity and natural gas. To manage the volatility relating to these exposures, the Company uses a variety of non-derivative and derivative instruments, including options, futures contracts and swaps. These derivatives are used principally for hedging purposes. The Company has a Risk Policy Committee, comprised of FirstEnergy executive officers, which exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. The Company uses derivatives to hedge the risk of price. The Company's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The majority of the Company's forward commodity contracts are considered "normal purchases and sales," as defined by SFAS 133, and are therefore excluded from the scope of SFAS 138. The options and futures contracts determined to be within the scope of SFAS 133 are accounted for as cash flow hedges and expire on various dates through 2003. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. There is currently a net deferred loss of $1.9 million included in Accumulated Other Comprehensive Income as of December 31, 2002 related to derivative hedging activity, which will be reclassified to earnings during the next twelve months as hedged transactions occur. (J) REGULATORY ASSETS- The Companies recognize, as regulatory assets, costs which the FERC and PPUC have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Company's regulatory plan. The Company continues to bill and collect cost-based rates for its transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2002 2001 ---------------------------------------------------------- (In millions) Regulatory transition charge......... $434.2 $515.9 Customer receivables for future income taxes....................... 124.5 140.2 Provider of last resort deferrals.... -- 83.5 Nuclear decommissioning costs........ 35.8 24.0 Loss on reacquired debt.............. 5.2 5.8 Other................................ -- 0.4 ---------------------------------------------------------- Total.............................. $599.7 $769.8 ========================================================== 2. MERGER: On November 7, 2001, the merger of FirstEnergy and GPU became effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000. As a result of the merger, GPU's former wholly owned subsidiaries, including the Company, became wholly owned subsidiaries of FirstEnergy. The merger was accounted for by the purchase method of accounting. The assets acquired and liabilities assumed were recorded at estimated fair values as determined by FirstEnergy's management based on information currently available and on current assumptions as to future operations. Merger purchase accounting adjustments recorded in the records of the Company primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. Other assets and liabilities were not adjusted since they remain subject to rate regulation on a historical cost basis. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. During 2002, certain pre-acquisition contingencies and other final adjustments to the fair values of the assets acquired and liabilities assumed were reflected in the final allocation of the purchase price. These adjustments primarily related to: (1) final actuarial calculations related to pension and postretirement benefit obligations; (2) establishment of a reserve for deferred energy costs recognized prior to the merger; and (3) return to accrual adjustments for income taxes. As a result of these adjustments, goodwill increased by approximately $100.7 million. As of December 31, 2002, the Company had recorded goodwill of approximately $898.1 million related to the merger. 24 3. LEASES: Consistent with regulatory treatment, the rentals for capital leases are charged to operating expenses on the Consolidated Statements of Income. The Company has a capital lease for an operations building, which expires in 2004. In each of the years 2002, 2001 and 2000, total rentals related to this capital lease were $0.7 million, comprised of an interest element of $0.2 million and other costs of $0.5 million. As of December 31, 2002, the future minimum lease payments on the Company's capital lease discussed above are $0.7 million and $0.5 million for the years 2003 and 2004, respectively. The present value of the net minimum lease payments is $1.1 million and the total interest portion is $0.1 million. 4. CAPITALIZATION: (A) RETAINED EARNINGS- The merger purchase accounting adjustments included resetting the retained earnings balance to zero at the November 7, 2001 merger date. In general, the Company's first mortgage bond (FMB) indentures restrict the payment of dividends or distributions on or with respect to the Company's common stock to amounts credited to earned surplus since approximately the date of its indenture. At such date, the Company had a balance of $10.1 million in its earned surplus account, which would not be available for dividends or other distributions. As of December 31, 2002, the Company had retained earnings available to pay common stock dividends of $22.6 million, net of amounts restricted under the Company's FMB indentures. (B) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 2002 2001 2000 - -------------------------------------------------------------------------- Restricted common shares granted......... 36,922 133,162 208,400 Weighted average market price............ $36.04 $35.68 $26.63 Weighted average vesting period (years).. 3.2 3.7 3.8 Dividends restricted..................... Yes * Yes - -------------------------------------------------------------------------- * FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2002, there were 296,008 stock units outstanding. 25 Stock option activities under the FE Programs for the past three years were as follows: Number of Weighted Average Stock Option Activities Options Exercise Price - -------------------------------------------------------------------------------- Balance, January 1, 2000............. 2,153,369 $25.32 (159,755 options exercisable)........ 24.87 Options granted.................... 3,011,584 23.24 Options exercised.................. 90,491 26.00 Options forfeited.................. 52,600 22.20 Balance, December 31, 2000.......... 5,021,862 24.09 (473,314 options exercisable)........ 24.11 Options granted.................... 4,240,273 28.11 Options exercised.................. 694,403 24.24 Options forfeited.................. 120,044 28.07 Balance, December 31, 2001........... 8,447,688 26.04 (1,828,341 options exercisable)...... 24.83 Options granted.................... 3,399,579 34.48 Options exercised.................. 1,018,852 23.56 Options forfeited.................. 392,929 28.19 Balance, December 31, 2002.......... 10,435,486 28.95 (1,400,206 options exercisable)...... 26.07 As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 1E - Stock-Based Compensation. (C) PREFERRED AND PREFERENCE STOCK- The Company's preferred stock authorization consists of 11.435 million shares without par value. No preferred shares are currently outstanding. (D) COMPANY-OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY PARTNERSHIP PREFERRED SECURITIES- The Company has formed a statutory business trust, Penelec Capital Trust, which is owned through a wholly-owned limited partnership of the Company, Penelec Capital II, L.P., of which a wholly-owned subsidiary of the Company is the sole general partner. In this transaction, Penelec Capital Trust invested the gross proceeds from the sale of $100.0 million of its 7.34% trust preferred securities in the preferred securities of Penelec Capital II, L.P., which in turn invested those proceeds in $103.1 million of 7.34% subordinated debentures of the Company. The sole assets of Penelec Capital Trust are the preferred securities of Penelec Capital II, L.P., whose sole assets are the Company's subordinated debentures with the same rate and maturity date as the preferred securities. The Company has effectively provided a full and unconditional guarantee of its obligations under its trust's preferred securities. The trust preferred securities, which mature in 2039 and have a liquidation value of $25.00 per security, are redeemable at the option of the Company beginning in September 2004 at 100% of their principal amount. The interest on the subordinated debentures (and therefore the distributions on the preferred securities) may be deferred for up to 60 months, but the Company may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full. 26 (E) LONG-TERM DEBT- The Company's first mortgage bond indenture, which secures all of the Company's FMBs, serve as a direct first mortgage lien on substantially all of the Company's property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of these relate to the nonpayment of interest and/or principal on debt, which could trigger a default. Cross-default provisions also exist between FirstEnergy and the Company. Based on the amount of bonds authenticated by the Trustee through December 31, 2002, the Company's annual sinking and improvement fund requirements for all bonds issued under the mortgage amount to $0.7 million. The Company expects to fulfill its sinking and improvement fund obligation by providing bondable property additions to the Trustee. Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) ------------------------- 2003..........$ 0.2 2004.......... 125.2 2005.......... 8.2 2006.......... 0.2 2007.......... 3.1 ------------------------- The Company's obligations to repay certain pollution control revenue bonds are secured by several series of FMBs. Certain pollution control revenue bonds are entitled to the benefit of noncancelable municipal bond insurance policies of $69.3 million to pay principal of, or interest on, the pollution control revenue bonds. (F) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with the Company's parent. As of December 31, 2002, accumulated other comprehensive income consisted of an unrealized gain on investments of $2,700 and an unrealized loss on derivative instruments of $72,000. 5. SHORT-TERM BORROWINGS: The Company may borrow from its affiliates on a short-term basis. As of December 31, 2002, the Company had total short-term borrowings of $90.4 million from its affiliates with a weighted average interest rate of approximately 1.8%. 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $328 million for property additions and improvements from 2003 through 2007, of which approximately $54 million is applicable to 2003. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its present ownership interest in TMI-2, the Company is exempt from any potential assessment under the industry retrospective rating plan. The Company is also insured as to its interest in TMI-2 under a policy issued to the operating company for the plant. Under this policy, $150 million is provided for property damage and decontamination and decommissioning costs. Under this policy, the Company can be assessed a maximum of approximately $0.2 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at TMI-2 exceed the policy limits of the insurance in effect with respect to 27 that plant, to the extent a nuclear incident is determined not to be covered by the Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs. (C) ENVIRONMENTAL MATTERS- The Company has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, 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 Company's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. The Company has accrued liabilities aggregating approximately $0.3 million as of December 31, 2002. The Company does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. (D) OTHER LEGAL PROCEEDINGS- Various lawsuits, claims and proceedings related to the Company's normal business operations are pending against the Company, the most significant of which is described below. The Company has a 25% ownership interest in TMI-2, which was damaged during a 1979 accident. As a result of the accident, claims for alleged personal injury were filed against the Company, JCP&L, Met-Ed, and GPU (the defendants) in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by the defendants and dismissed the ten initial "test cases" which had been selected for a test case trial. In January 2002, the District Court granted the defendants' July 2001 motion for summary judgment on the remaining 2,100 pending claims. In February 2002, the plaintiffs filed a notice of appeal to the United States Court of Appeals for the Third Circuit. In December 2002, the Court of Appeals refused to hear the appeal, which effectively ended further legal action for those claims. 7. OTHER INFORMATION: The following represents the financial data which includes supplemental unaudited prior years' information as compared to consolidated financial statements and notes previously reported in 2001 and 2000. (A) CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2000 ---- ---- ---- ---- Other cash flows from operating activities: Accrued taxes................................ $(7,984) $26,337 | $(21,377) $ 4,994 All other.................................... 15,931 15,253 | (15,507) (94,119) ------- ------- | --------- -------- Other cash provided from (used for) | operating activities..................... $ 7,947 $41,590 | $(36,884) $(89,125) ======= ======= | ========= ========
(B) REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS- The Company records purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." The aggregate purchase and sales transactions for the three years ended December 31, 2002, are summarized as follows: Nov. 7-Dec. 31, Jan. 1-Nov. 6, 2002 2001 2001 2000 ---------------------------------------------------------- (In millions) Sales....... $34 $1 | $29 $92 Purchases... 75 9 | 79 36 ----------------------------------|----------------------- The Company's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from the PJM ISO from power sales (as reflected in the table above) during periods when the Company had additional available power capacity. Revenues also include sales by the Company of power sourced from the PJM ISO 28 (reflected as purchases in the table above) during periods when the Company required additional power to meet its retail load requirements. (C) TRANSACTIONS WITH AFFILIATED COMPANIES- The primary affiliated companies transactions are as follows: Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2000 - ------------------------------------------------------------------------------ (In millions) Operating Revenues: Wholesale sales-affiliated companies... $ 9.1 $ 1.1 | $10.0 $ 30.1 | Operating Expenses: | Power purchased from FES............... 188.2 14.6 | -- -- GPU Service, Inc. support services..... 81.5 17.0 | 93.0 109.0 Power purchased from other affiliates.. 9.7 1.5 | 8.8 2.6 (D) RETIREMENTS BENEFITS- (1) Net pension and other postretirement benefit costs (income) for the three years ended December 31, 2002 are approximately as follows: Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2000 - ------------------------------------------------------------------------------ (In millions) Pension Benefits...................... $(15.8) $(4.6) | $(14.9) $(9.3) Other Postretirement Benefits......... 3.2 0.3 | 2.8 8.9 (1) Includes estimated portion of benefit costs included in billings from GPUS. 8. RECENTLY ISSUED ACCOUNTING STANDARDS: FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Company does not believe that implementation of FIN 45 will be material but it will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. The Company currently has transactions with entities in connection with the sale of preferred securities, which may fall within the scope of this interpretation, and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. The Company currently consolidates these entities and believes it will continue to consolidate following the adoption of FIN 46. 9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001. 29 Three Months Ended --------------------------------------------- March 31, June 30, September 30,December 31, 2002 2002 2002 2002 - ------------------------------------------------------------------------------ (In millions) Operating Revenues............ $242.8 $237.6 $269.4 $277.3 Operating Expenses and Taxes.. 214.3 221.7 256.4 246.5 - ------------------------------------------------------------------------------ Operating Income ............. 28.5 15.9 13.0 30.8 Other Income (Expense)........ 0.3 0.8 1.0 (0.4) Net Interest Charges.......... 10.0 9.8 9.6 9.6 - ------------------------------------------------------------------------------ Net Income ................... $ 18.8 $ 6.9 $ 4.4 $ 20.8 ==============================================================================
Three Months Ended -------------------------------- March 31, June 30, September 30, Oct. 1 - Nov. 6, Nov. 7 - Dec. 31, 2001 2001 2001 2001 2001 - ----------------------------------------------------------------------------------------------------- (In millions) Operating Revenues............ $243.8 $230.6 $265.6 $94.5 | $140.1 Operating Expenses and Taxes.. 235.0 212.2 238.8 78.5 | 125.7 - ----------------------------------------------------------------------------------|------------------ Operating Income.............. 8.8 18.4 26.8 16.0 | 14.4 Other Income (Expense)........ 0.6 1.4 (1.2) (7.4) | 3.0 Net Interest Charges.......... 11.5 12.6 11.2 4.4 | 6.6 - ----------------------------------------------------------------------------------|------------------ Net Income (Loss)............. $(2.1) $ 7.2 $ 14.4 R 4.2 | $ 10.8 =====================================================================================================
30 Report of Independent Accountants To the Stockholders and Board of Directors of Pennsylvania Electric Company: In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of Pennsylvania Electric Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended and the year ended December 31, 2000 (pre-merger) in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The consolidated financial statements of Pennsylvania Electric Company and subsidiaries as of December 31, 2001 and for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger) were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financials statements in their report dated March 18, 2002. PricewaterhouseCoopers LLP Cleveland, Ohio February 28, 2003 31 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. Report of Previous Independent Public Accountants To the Stockholders and Board of Directors of Pennsylvania Electric Company: We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Pennsylvania Electric Company (a Pennsylvania corporation and wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2001 (post-merger), and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Pennsylvania Electric Company and subsidiaries as of December 31, 2000 and for each of the two years in the period ended December 31, 2000 (pre-merger), were audited by other auditors whose report dated January 31, 2001, expressed an unqualified opinion on those statements. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the 2001 financial statements referred to above present fairly, in all material respects, the financial position of Pennsylvania Electric Company and subsidiaries as of December 31, 2001 (post-merger), and the results of their operations and their cash flows for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger), in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. 32 EX-21 40 pn_ex21-6.txt EX. 21-6 LIST OF SUBS - PENELEC Exhibit 21.6 PENNSYLVANIA ELECTRIC COMPANY SUBSIDIARIES OF THE REGISTRANT AT DECEMBER 31, 2002 STATE OF NAME OF SUBSIDIARY BUSINESS ORGANIZATION ------------------ -------- ------------ NINEVEH WATER COMPANY WATER SERVICE PENNSYLVANIA THE WAVERLY ELECTRIC LIGHT ELECTRIC DISTRIBUTION PENNSYLVANIA AND POWER COMPANY PENELEC PREFERRED CAPITAL II, INC. SPECIAL-PURPOSE FINANCE DELAWARE PENELEC CAPITAL II, L.P. SPECIAL-PURPOSE FINANCE DELAWARE PENELEC CAPITAL TRUST SPECIAL-PURPOSE FINANCE DELAWARE Note: Penelec, along with its affiliates JCP&L and Met-Ed, collectively own all of the common stock of Saxton Nuclear Experimental Corporation, a Pennsylvania nonprofit corporation organized for nuclear experimental purposes which is now inactive. The carrying value of the owners' investment has been written down to a nominal value. EX-23 41 pn_ex23-4.txt EX. 23-4 PWC CONSENT - PENELEC EXHIBIT 23.4 PENNSYLVANIA ELECTRIC COMPANY CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-62295, 333-62295-01 and 333-62295-02) of Pennsylvania Electric Company of our report dated February 28, 2003 relating to the consolidated financial statements, which appears in the Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report dated February 28, 2003 relating to the financial statement schedule, which appears in this Form 10-K. PricewaterhouseCoopers LLP Cleveland, Ohio March 24, 2003 -----END PRIVACY-ENHANCED MESSAGE-----