-----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, HEZzjj5y3yuvTBq5ORkmMy0nijjQ710XjX96CrTKSsrxmIlxUGOZ3ijV5AHK/HiL 4moubuuJWvDQ5CEO0E03bQ== 0000950152-03-007828.txt : 20030819 0000950152-03-007828.hdr.sgml : 20030819 20030819172950 ACCESSION NUMBER: 0000950152-03-007828 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 14 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030819 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/A SEC ACT: 1934 Act SEC FILE NUMBER: 001-02323 FILM NUMBER: 03856597 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: 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/A SEC ACT: 1934 Act SEC FILE NUMBER: 001-02578 FILM NUMBER: 03856598 BUSINESS ADDRESS: STREET 1: 76 S MAIN ST CITY: AKRON STATE: OH ZIP: 44308 BUSINESS PHONE: 2163845100 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/A SEC ACT: 1934 Act SEC FILE NUMBER: 001-03583 FILM NUMBER: 03856596 BUSINESS ADDRESS: STREET 1: 76 SOUTH MAIN STREET CITY: AKRON STATE: OH ZIP: 43308 BUSINESS PHONE: 2166229800 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/A SEC ACT: 1934 Act SEC FILE NUMBER: 333-21011 FILM NUMBER: 03856599 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 10-K/A 1 l02705ae10vkza.txt FIRSTENERGY CORP 10-K/A SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K/A (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. - ----------- ----------------------------- ------------------ AMENDMENT NO. 2 333-21011 FIRSTENERGY CORP. 34-1843785 (AN OHIO CORPORATION) 76 SOUTH MAIN STREET AKRON, OH 44308 TELEPHONE (800)736-3402 AMENDMENT NO. 1 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
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
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
FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. Documents incorporated by reference (to the extent indicated herein):
PART OF FORM 10-K/A 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
This combined Form 10-K/A is separately filed by FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison 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 three FirstEnergy subsidiary registrants is also attributed to FirstEnergy. EXPLANATORY NOTE As described in Note 2(M) to the consolidated financial statements of First Energy Corp. and Note 1(M) to the consolidated financial statements of Ohio Edison Company, the Registrants are restating their financial statements for the year ended December 31, 2002. As described in Note 1(M) to the consolidated financial statements of The Cleveland Electric Illuminating Company and The Toledo Edison Company, these Registrants are restating their financial statements for the three years ended December 31, 2002. The restatements principally reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. The Registrants are filing amended Annual Reports on the Form 10-K/A to reflect the restatements. THE FOLLOWING ITEMS HAVE BEEN AMENDED IN THIS AMENDMENT NO. 2: PART I ITEM 1. BUSINESS PART II ITEM 6. SELECTED FINANCIAL DATA ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA PART III ITEM 14. CONTROLS AND PROCEDURES PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K FORM 10-K/A TABLE OF CONTENTS
PAGE ---- PART I Item 1. Business.................................................................................... 1 Recent Developments....................................................................... 1 Environmental Matters................................................................... 1 Regulatory Matters...................................................................... 1 International Operations................................................................ 2 Other Matters........................................................................... 3 The Company............................................................................... 3 Divestitures.............................................................................. 4 International Operations................................................................ 3 Generating Assets....................................................................... 3 Utility Regulation........................................................................ 3 PUCO Rate Matters....................................................................... 4 NJBPU Rate Matters...................................................................... 4 PPUC Rate Matters....................................................................... 5 FERC Rate Matters....................................................................... 6 Regulatory Accounting................................................................... 7 Capital Requirements...................................................................... 7 Met-Ed Capital Trust and Penelec Capital Trust............................................ 9 Nuclear Regulation........................................................................ 9 Nuclear Insurance......................................................................... 10 Environmental Matters..................................................................... 11 Air Regulation.......................................................................... 11 Water Regulation........................................................................ 12 Waste Disposal.......................................................................... 12 Summary................................................................................. 12 Fuel Supply............................................................................... 13 System Capacity and Reserves.............................................................. 13 Regional Reliability...................................................................... 14 Competition............................................................................... 14 Research and Development.................................................................. 15 Executive Officers........................................................................ 15 FirstEnergy Website....................................................................... 15 Item 2. Properties.................................................................................. * Item 3. Legal Proceedings........................................................................... * Item 4. Submission of Matters to a Vote of Security Holders......................................... * PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................... * Item 6. Selected Financial Data..................................................................... 16 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....... 16 Item 8. Financial Statements and Supplementary Data................................................. 16 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure........ * PART III Item 10. Directors and Executive Officers of the Registrant.......................................... * Item 11. Executive Compensation...................................................................... * Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters....................................................................... * Item 13. Certain Relationships and Related Transactions.............................................. * Item 14. Controls and Procedures..................................................................... 16 PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 16
* Indicates the items that have not been revised and are not included in this Form 10-K/A. Reference is made to the original 10-K for the complete text of such items. PART 1 ITEM 1. BUSINESS RECENT DEVELOPMENTS ENVIRONMENTAL MATTERS- On August 8, 2003, FirstEnergy Corp. (FirstEnergy), Ohio Edison Company (OE) and Pennsylvania Power Company (Penn) reported a development regarding a complaint filed by the U.S. Department of Justice with respect to the W.H. Sammis Plant (see Note 7(D) Commitments, Guarantees and Contingencies - Environmental Matters). As reported, on August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning March 15, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, may have a material adverse impact on the Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter. REGULATORY MATTERS- New Jersey On July 25, 2003, FirstEnergy and Jersey Central Power & Light Company (JCP&L)JCP&L announced that they are reviewing is underway concerning a decision by the New Jersey Board of Public Utilities (NJBPU) on JCP&L's rate proceeding (See Note 2(D)). Based on that review, JCP&L will decide its appropriate course of action, which could include filing a request for reconsideration with the NJBPU and possibly an appeal to the Appellate Division of the Superior Court of New Jersey. In its ruling, the NJBPU reduced JCP&L's annual revenues by approximately $62 million, for an average rate decrease of 3 percent, effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5 percent on JCP&L's rate base for the next 6 to 12 months. During that period, JCP&L would initiate another proceeding to request recovery of additional expenses incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75 percent or decrease it to 9.25 percent, depending on its assessment of the reliability of JCP&L's service. Any reduction could be retroactive to August 1, 2003. The NJBPU decision reflects elimination of $111 million in annual customer credits mandated by the New Jersey Electric Discount and Energy Competition Act (EDECA); a $223 million reduction in the energy delivery charge; a net $1 million increase in the Societal Benefits Charge (SBC); and a $49 million increase in the Market Transition Charge (MTC). The $1 million net SBC increase reflects approximately a $22 million increase related to universal services costs previously approved in a separate proceeding, as well as reductions in other components of the SBC. The MTC would allow for the recovery of $465 million in deferred energy costs over the next 10 years on an interim basis, thus disallowing $153 million of the $618 million provided for in the settlement agreement. This decision reflects the NJBPU's belief that a hindsight review comparing JCP&L's power purchases to spot market prices provides the appropriate benchmark for recovery. JCP&L's deferred energy costs primarily reflect mandated purchase power contracts with NUGs that are above wholesale market prices, and costs of providing basic generation service to customers in excess of the company's capped basic generation service charges during the transition period under EDECA, which ends August 1, 2003. At that time, the generation portion of most customer bills will increase by an average of 7.5 percent as a result of the outcome of the basic generation service auction conducted earlier this year by the BPU. In the second quarter of 2003, JCP&L recorded charges aggregating $158 million ($94 million after tax) consisting of the $153 million deferred energy costs and other regulatory assets. On July 25, 2003, the NJBPU approved a Stipulation of Settlement between the parties and authorized the recovery of the total $135 million of the Freehold buyout costs, eliminating the interim nature of the recovery. 1 Pennsylvania On April 2, 2003, the Pennsylvania Public Utilities Commission (PPUC) remanded the merger savings issue to the Office of Administrative Law Judge (ALJ) and directed Met-Ed and Penelec to submit a position paper by May 2, 2003 on the status of the Settlement Stipulation in light of the Commonwealth Court's decision (Court Order). In summary, Met-Ed and Penelec submitted to the PPUC the following position: - On January 16, 2003, the Pennsylvania Supreme Court denied or quashed all appeals arising from the Court Order, thus rendering the Court Order final. - Because the parties sought request for a stay of the PPUC's June 20, 2001 order in which the Settlement Stipulation was approved, all terms and conditions included therein that were not inconsistent with the Court Order remained in effect. - Only those provisions related to PLR cost recovery and PLR deferral issues addressed by the PPUC and expressly rejected by the Commonwealth Court, must be removed from the Settlement Stipulation. - The GENCO Code of Conduct must be reinstated consistent with the Court Order. - All other provisions included in the Settlement Stipulation unrelated to these three issues remain in effect. On or about June 2, 2003, parties filed comments in response to the position presented by Met-Ed and Penelec. The other parties' responses included significant disagreement with the position paper and disagreement among the other parties themselves, including the Stipulation's original signatory parties. Some parties believe that no portion of the Stipulation has survived the Commonwealth Court's Order. Based upon these comments, it became clear that many of the parties not only disagreed with Met-Ed and Penelec, but also disagreed among themselves. Partially because of this lack of consensus among the parties, Met-Ed and Penelec submitted a letter on June 11, 2003, to the ALJ informing the ALJ and all other parties that Met-Ed and Penelec were voiding the Settlement Stipulation, pursuant to the termination provisions found therein. Notwithstanding the voiding of the Settlement Stipulation, Met-Ed and Penelec voluntarily agreed to retain virtually all of the customer benefits provided by the Settlement Stipulation, including, among others, funding for renewable energy resource and demand response programs. Met-Ed and Penelec also agreed to cap distribution rates at current levels through 2007, provided that the PPUC finds during the remanded merger saving proceedings that Met-Ed and Penelec have satisfied the public interest test applicable to mergers and leave the quantification of merger savings for a subsequent rate proceedings. They believe this will significantly simplify the issues in the pending action by reinstating Met-Ed's and Penelec's Restructuring Settlement previously approved by the PPUC. In addition, they have agreed to voluntarily continue certain Stipulation provisions including funding for energy and demand side response programs and to cap distribution rates at current levels through 2007. This voluntary distribution rate cap is contingent upon a finding that Met-Ed and Penelec have satisfied the "public interest" test applicable to mergers and that any rate impacts of merger savings will be dealt with in a subsequent rate case. Met-Ed and Penelec believe that their actions in voiding the Settlement Stipulation will simplify the issues and limit them to the treatment of merger savings and whether Met-Ed's and Penelec's accounting is consistent with the Court Order. INTERNATIONAL OPERATIONS- Pending Sale of Remaining Investment in Avon and Sale of Note from Aquila On May 22, 2003, FirstEnergy announced it reached an agreement to sell its 20.1 percent interest in Avon to Scottish and Southern Energy plc; that agreement also includes Aquila's 79.9 percent interest (See Note 3). Under terms of the agreement, which is subject to bondholder approval, Scottish and Southern will pay FirstEnergy and Aquila an aggregate $70 million (FirstEnergy's share would be approximately $14 million). Avon's debt will remain with that company. FirstEnergy recognized in the second quarter of 2003 an impairment of $12.6 million ($8.2 million after tax) related to the carrying value of the note receivable from the initial sale of a 79.9 percent interest in Avon that occurred in May 2002. After receiving the first annual installment payment of $19 million in May 2003, FirstEnergy sold the remaining balance of the note in the secondary market and received $63.2 million in proceeds on July 28, 2003. Emdersa On April 18, 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. As a result of the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67.4 million, or $0.23 per share of common stock in the second quarter of 2003. This charge is the result of realizing the Currency Translation Adjustment (CTA) losses through current period earnings ($89.8 million, or $0.30 per share), partially offset by the gain recognized from abandoning FirstEnergy's investment in Emdersa ($22.4 million, or 2 $0.07 per share). Since FirstEnergy had previously recorded $90 million of CTA adjustments in OCI, the net effect of the $67.4 million charge was an increase in common stockholders' equity of $22.4 million. The $67.4 million charge does not include the anticipated income tax benefits related to the abandonment, which were fully reserved during the second quarter. FirstEnergy anticipates tax benefits of approximately $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million of tax benefits would reduce goodwill recognized in connection with the acquisition of GPU. See note 2(M) to the FirstEnergy Consolidated Financial Statements for discussion or classification of a discontinued operation in the Revised Financial Statements. OTHER MATTERS - It is FirstEnergy's understanding that, as of August 18, 2003, five individual shareholder-plaintiffs have filed separate complaints against FirstEnergy Corp. alleging various securities law violations in connection with the restatement of earnings described herein. Most of these complaints have not yet been officially served on the Company. Moreover, FirstEnergy is still reviewing the suits that have been served in preparation for a responsive pleading. FirstEnergy is, however, aware that in each case, the plaintiffs are seeking certification from the court to represent a class of similarly situated shareholders. On August 14, 2003, eight states in the Northeast U.S. and southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. The cause of the outage has not been determined. Having restored service to its customers, FirstEnergy is now in the process of accumulating data and evaluating the status of its electrical system prior to and during the outage event and would expect that the same effort is under way at utilities and regional transmission operators across the region. As of August 18, 2003, the following facts about FirstEnergy's system were known. Early in the afternoon of August 14, hours before the event, Unit 5 of the Eastlake Plant in Eastlake, Ohio, tripped off. Later in the afternoon, three FirstEnergy transmission lines and one owned by American Electric Power and FirstEnergy tripped out of service. The Midwest Independent System Operator (MISO), which oversees the regional transmission grid, indicated that there were a number of other transmission line trips in the region outside of FirstEnergy's system. FirstEnergy customers experienced no service interruptions resulting from these conditions. Indications to FirstEnergy were that the Company's system was stable. Therefore, no isolation of FirstEnergy's system was called for. In addition, FirstEnergy determined that its computerized system for monitoring and controlling its transmission and generation system was operating, but the alarm screen function was not. However, MISO's monitoring system was operating properly. FirstEnergy believes that extensive data needs to be gathered and analyzed in order to determine with any degree of certainty the circumstances that led to the outage. This a very complex situation, far broader than the power line outages FirstEnergy experienced on its system. From the preliminary data that has been gathered, FirstEnergy believes that the transmission grid in the Eastern Interconnection, not just within FirstEnergy's system, was experiencing unusual electrical conditions at various times prior to the event. These included unusual voltage and frequency fluctuations and load swings on the grid. FirstEnergy is committed to working with the North American Electric Reliability Council and others involved to determine exactly what events in the entire affected region led to the outage. There is no timetable as to when this entire process will be completed. It is, however, expected to last several weeks, at a minimum. 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, 3 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 4 Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," with physically and operationally separable activities. Application of Emerging Issues Task Force (EITF) Issue No. 87-11, "Allocation of Purchase Price to Assets to Be Sold," required that expected, pre-sale cash flows, including incremental interest costs on related acquisition debt, of these operations be considered part of the purchase price allocation. Accordingly, subsequent to the merger date, results of operations and incremental interest costs related to these international subsidiaries were not included in FirstEnergy's 2001 Consolidated Statements of Income. Additionally, assets and liabilities of these international operations were segregated under separate captions on the Consolidated Balance Sheet as of December 31, 2001 as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale." Upon completion of its merger with GPU, FirstEnergy accepted an October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase Avon Energy Partners Holdings (Avon), FirstEnergy's wholly owned holding company for Midlands Electricity plc, for $2.1 billion (including the assumption of $1.7 billion of debt). The transaction closed on May 8, 2002 and reflected the March 2002 modification of Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest in Avon for approximately $1.9 billion (including the assumption of $1.7 billion of debt). Proceeds to FirstEnergy included $155 million in cash and a note receivable for approximately $87 million (representing the present value of $19 million per year to be received over six years beginning in 2003) from Aquila for its 79.9 percent interest. FirstEnergy and Aquila together own all of the outstanding shares of Avon through a jointly owned subsidiary, with each company having an ownership voting interest. Originally, in accordance with applicable accounting guidance, the earnings of those foreign operations were not recognized in current earnings from the date of the GPU acquisition. However, as a result of the decision to retain an ownership interest in Avon, EITF Issue No. 90-6, "Accounting for Certain Events Not Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be Sold" required FirstEnergy to reallocate the purchase price of GPU based on amounts as of the purchase date as if Avon had never been held for sale, including reversal of the effects of having applied EITF Issue No. 87-11, to the transaction. The effect of reallocating the purchase price and reversal of the effects of EITF Issue No. 87-11, including the allocation of capitalized interest, has been reflected in the Consolidated Statement of Income for the year ended December 31, 2002 by reclassifying certain revenue and expense amounts related to activity during the quarter ended March 31, 2002 to their respective income statement classifications. See Note 2(L) of Notes to FirstEnergy's Consolidated Financial Statements for the effects of the change in classification. In the fourth quarter of 2002, FirstEnergy recorded a $50 million charge ($32.5 million net of tax) to reduce the carrying value of its remaining 20.1 percent interest. GPU's former Argentina operations were also identified by FirstEnergy for divestiture within one year of the merger. FirstEnergy determined the fair value of its Argentina operations, GPU Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa), based on the best available information as of the date of the merger. Subsequent to that date, a number of economic events have occurred in Argentina which may have an impact on FirstEnergy's ability to realize Emdersa's estimated fair value. These events include currency devaluation, restrictions on repatriation of cash, and the anticipation of future asset sales in that region by competitors. FirstEnergy did not reach a definitive agreement to sell Emdersa as of December 31, 2002. Therefore, these assets were no longer classified as "Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2002 and Emdersa's results of operations were included in FirstEnergy's 2002 Consolidated Statement of Income. Additionally, under EITF Issue No. 90-6, FirstEnergy recorded in the fourth quarter of 2002 a one-time, non-cash charge included as a "Cumulative Adjustment for Retained Businesses Previously Held for Sale" on its 2002 Consolidated Statement of Income related to Emdersa's cumulative results of operations from November 7, 2001 through September 30, 2002. The amount of this one-time, after-tax charge was $93.7 million, or $0.32 per share of common stock (comprised of $108.9 million in currency transaction losses arising principally from U.S. dollar denominated debt, offset by $15.2 million of operating income). See Note 2(L) of Notes to First Energy's Consolidated Financial Statements for the effects of the change in classification. On October 1, 2002, FirstEnergy began consolidating the results of Emdersa's operations in its financial statements. In addition to the currency transaction losses of $108.9 million, FirstEnergy recognized a currency translation adjustment (CTA) in other comprehensive income (OCI) of $91.5 million as of December 31, 2002, which reduced FirstEnergy's common stockholders' equity. This adjustment represents the impact of translating Emdersa's financial statements from its functional currency to the U.S. dollar for financial reporting in conformity with accounting principles generally accepted in the United States (GAAP). On April 18, 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. As a result of the abandonment, FirstEnergy will recognize a one-time, non-cash charge of $63 million, or $0.21 per share of common stock in the second quarter of 2003. This charge is the result of realizing the CTA losses through the current period earnings ($90 million, or $0.30 per share), partially offset by the gain recognized from eliminating its investment in Emdersa ($27 million, or $0.09 per share). Since FirstEnergy has previously recorded $90 million of CTA adjustments in OCI, the net effect of the $63 million charge will be an increase in common stockholders' equity of $27 million. The $63 million charge does not include the anticipated income tax benefits related to the abandonment. These tax benefits will be fully reserved during the second quarter. FirstEnergy anticipates tax benefits of approximately 5 $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million tax benefits would reduce goodwill recognized in connection with the acquisition of GPU. Generating Assets In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 megawatts (MW) to NRG Energy Inc. On August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves the right to pursue legal action against NRG, its affiliate and its parent, Xcel Energy, for damages, based on the anticipatory breach of the agreement. NRG declared bankruptcy 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 bids received from other bids 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: - allowing the Companies' electric customers to select their generation suppliers; - establishing provider of last resort (PLR) obligations to customers in the Companies' service areas; - allowing recovery of potentially stranded investment (sometimes referred to as transition costs); - itemizing (unbundling) the current price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; - deregulating the Companies' electric generation businesses; and - 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 6 $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 with GPU. 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 7 of deferred costs to a retrospective prudence review during a period of extreme price uncertainty and volatility in the energy markets. Although JCP&L disagrees with the potential disallowances, it is pleased with the report's major conclusions and overall tone. Hearings concluded on April 28, 2003, and initial briefs were filed on May 7, 2003. The Administrative Law Judge's recommended decision is due by the end of June 2003 and the NJBPU's subsequent decision is due in July 2003. In 1997, the NJBPU authorized JCP&L to recover from customers, subject to possible refund, $135 million of costs incurred in connection with a 1996 buyout of a power purchase agreement. JCP&L has recovered the full $135 million; the NJBPU has established a procedural schedule to take further evidence with respect to the buyout to enable it to make a final prudence determination contemporaneously with the resolution of the pending rate case. In December 2001, the NJBPU authorized the auctioning of BGS for the period from August 1, 2002 through July 31, 2003 to meet the electricity demands of all customers who have not selected an alternative supplier. The auction results were approved by the NJBPU in February 2002, removing JCP&L's BGS obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In February 2003, the NJBPU approved the BGS auction results for the period beginning August 1, 2003. The auction covered a fixed price bid (applicable to all residential and smaller commercial and industrial customers) and an hourly price bid (applicable to all large industrial customers) process. JCP&L will sell all self-supplied energy (NUGs and owned generation) to the wholesale market with offsets to its deferred energy balances. PPUC Rate Matters The PPUC authorized 1998 rate restructuring plans for Penn, Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Similar to JCP&L's situation, if the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income since the contingency existed prior to the merger. As a result of their generating asset divestitures, Met-Ed and Penelec obtained their supply of electricity to meet their PLR obligations almost entirely from contracted and open market purchases. In 2000, Met-Ed and Penelec filed a petition with the PPUC seeking permission to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates; the PPUC subsequently consolidated this petition in January 2001 with the FirstEnergy/GPU merger proceeding. 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 8 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 material 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 rates and the rates reflected in 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. 9
CAPITAL EXPENDITURES FORECAST 2002 -------------------------------------- ACTUAL 2003 2004-2007 TOTAL ------ ------ --------- ------ (IN MILLIONS) OE $ 81 $ 86 $ 182 $ 268 Penn 40 53 70 123 CEI 137 96 216 312 TE 91 54 115 169 JCP&L 100 102 360 462 Met-Ed 43 53 235 288 Penelec 49 54 274 328 ATSI 27 25 106 131 FES 185 124 699 823 Other subsidiaries . 151 80 67 147 ------ ------ ------ ------ Total $ 904 $ 727 $2,324 $3,051
During the 2003-2007 period, maturities of, and sinking fund requirements for, long-term debt and preferred stock of FirstEnergy and its subsidiaries are:
PREFERRED STOCK AND LONG-TERM DEBT REDEMPTION SCHEDULE -------------------------------------------- 2003 2004-2007 TOTAL ------ --------- ------ (IN MILLIONS) OE.............................. $ 210 $ 207 $ 417 Penn............................ 42 52 94 CEI............................. 146 704 850 TE.............................. 116 245 361 JCP&L........................... 174 510 684 Met-Ed.......................... 60 292 352 Penelec......................... -- 137 137 FirstEnergy..................... -- 1,695 1,695 Other subsidiaries.............. 327 40 367 ------ ------ ------ Total........................... $1,075 $3,882 $4,957
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. 10 The extent and type of future financings will depend on the need for external funds as well as market conditions, the maintenance of an appropriate capital structure and the ability of the Companies to comply with coverage requirements in order to issue first mortgage bonds and preferred stock. The Companies will continue to monitor financial market conditions and, where appropriate, may take advantage of economic opportunities to refund debt and preferred stock to the extent that their financial resources permit. The coverage requirements contained in the first mortgage indentures under which the Companies issue first mortgage bonds provide that, except for certain refunding purposes, the Companies may not issue first mortgage bonds unless applicable net earnings (before income taxes), calculated as provided in the indentures, for any period of twelve consecutive months within the fifteen calendar months preceding the month in which such additional bonds are issued, are at least twice annual interest requirements on outstanding first mortgage bonds, including those being issued. Under OE's first mortgage indenture, the availability of property additions is more restrictive than the earnings test at the present time and would limit the amount of first mortgage bonds issuable against property additions to $172 million. OE is currently able to issue $1.195 billion principal amount of first mortgage bonds against previously retired bonds without the need to meet the above restrictions. Under Penn's first mortgage indenture, other requirements also apply and are more restrictive than the earnings test at the present time. Penn is currently able to issue $323 million principal amount of first mortgage bonds, with up to $150 million of such amount issuable against property additions; the remainder could be issued against previously retired bonds. CEI and TE can issue $379 million and $144 million principal amount of first mortgage bonds against a combination of previously retired bonds and property additions, respectively. TE cannot currently issue first mortgage bonds. JCP&L, Met-Ed and Penelec are able to issue $393 million, $74 million and $7 million principal amount, respectively, of first mortgage bonds against previously retired bonds. OE's, Penn's, TE's and JCP&L's respective articles of incorporation prohibit the sale of preferred stock unless applicable gross income, calculated as provided in the articles of incorporation, is equal to at least 1-1/2 times the aggregate of the annual interest requirements on indebtedness and annual dividend requirements on preferred stock outstanding immediately thereafter. Based upon earnings for 2002, an assumed dividend rate of 9%, and no additional indebtedness, OE, Penn and JCP&L would be permitted, under the earnings coverage test contained in their respective charters, to issue at least $2.8 billion, $251 million and $1.2 billion of preferred stock, respectively; TE cannot currently issue preferred stock. There are no restrictions on the ability of CEI, Met-Ed and Penelec to issue preferred stock. 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. 11 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 anticipates that Davis-Besse will be ready for restart in the first half of the summer of 2003. However, the NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. In 2002, FENOC spent approximately $115 million in additional nuclear-related operation and maintenance costs, approximately $120 million in replacement power costs and approximately $63 million in capital expenditures related to the reactor head and restart. For 2003, FENOC expects to spend approximately $50 million in additional nuclear-related operation and maintenance costs and approximately $12-18 million in replacement power costs per month. These costs could increase if the length of the outage increases. The NRC has promulgated and continues to promulgate orders and regulations related to the safe operation of nuclear power plants and standards for decommissioning clean-up and final license termination. The Companies cannot predict what additional orders and regulations (including post-September 11, 2001 security enhancements) may be promulgated, design changes required or the effect that any such regulations or design changes or additional clean-up standards for final site release, or the consideration thereof, may have upon their nuclear plants. Although the Companies have no reason to anticipate an accident at any of their nuclear plants, if such an accident did happen, it could have a material but currently undeterminable adverse effect on FirstEnergy's consolidated financial position. In addition, such an accident at any operating nuclear plant, whether or not owned by the Companies, could result in regulations or requirements that could affect the operation, licensing, or decommissioning of plants that the Companies do own with a consequent but currently undeterminable adverse impact, and could affect the Companies' abilities to raise funds in the capital markets. NUCLEAR INSURANCE The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $9.5 billion (assuming 105 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $300 million; and (ii) $9.2 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $88.1 million (but not more than $10 million 12 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 (SO(2)) and particulates. In addition, the U.S. Environmental Protection Agency (EPA) promulgated an SO(2) 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 SO(2) 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 SO(2) regulations in Ohio that allows for compliance based 13 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 SO(2) and nitrogen oxide (NO(x)) reduction requirements under the Clean Air Act Amendments of 1990. SO(2) reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO(x) 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 NO(x) reductions from the Companies' Ohio, New Jersey and Pennsylvania facilities. The EPA's NO(x) Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NO(x) 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 NO(x) 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 NO(x) 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 14 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:
FOSSIL NUCLEAR ------ ------- OE.................... 74.5% 25.5% Penn.................. 34.6% 65.4% CEI................... 67.3% 32.7% TE.................... 61.8% 38.2% Total FirstEnergy..... 65.6% 34.4%
Generation from JCP&L's and Met-Ed's hydro and combustion turbine generation facilities was minimal in 2002. FirstEnergy currently has long-term coal contracts to provide approximately 12,400,000 tons for the year 2003. The contracts are shared among the Companies based on various economic considerations. This contract coal is produced primarily from mines located in Pennsylvania, Kentucky and West Virginia. The contracts expire at various times through December 31, 2019. The Companies estimate their 2003 coal requirements to be approximately 18,860,000 tons (OE - 7,250,000, Penn - 6,000,000, CEI - 4,170,000, and TE - 1,440,000) to be met from the long-term contracts discussed above and spot market purchases. See "Environmental Matters" for factors pertaining to meeting environmental regulations affecting coal-fired generating units. FirstEnergy has contracts for uranium material and conversion services through 2006. The enrichment services are contracted for the majority of the enrichment requirements for nuclear fuel through 2006. Fabrication 15 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 16 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. 17 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. 18 As of January 1, 2003, FirstEnergy's nonutility subsidiaries and the Companies had a total of 17,560 employees located in the United States as follows: FirstEnergy - 1,744, OE - 1,368, CEI - 974, TE - 508, Penn - 201, JCP&L - - 39, Met-Ed - 61, ATSI - 29, FES - 2,072, FENOC - 2,850, FSG - 3,317, MARBEL - 32 and GPUS - 4,365 (primarily employees supporting JCP&L, Met-Ed and Penelec). ITEM 6. SELECTED FINANCIAL DATA ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required for items 6 through 8 is incorporated herein by reference to Selected Financial Data, Management's Discussion and Analysis of Results of Operations and Financial Condition and Financial Statements included on the pages shown in the following table in FirstEnergy's 2002 Annual Report to Stockholders, as revised (Exhibit 13 below).
ITEM 6 ITEM 7 ITEM 8 ------ ------ ------ FirstEnergy.............. 4 5-31 32-74 OE....................... 1 2-14 15-36 CEI...................... 1 2-15 16-40 TE....................... 1 2-15 16-40
ITEM 14. CONTROLS AND PROCEDURES (A) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES The applicable 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 Effective June 1, 2003, the registrants implemented a new Enterprise Resource Planning (ERP) system. While the associated business process changes transform the internal control structure, management believes adequate controls have been properly integrated into the reengineered ERP-enabled processes and that internal controls will be enhanced. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (A) 1. FINANCIAL STATEMENTS Included in Part II of this report and incorporated herein by reference to FirstEnergy's 2002 Annual Report to Stockholders, as revised (Exhibit 13 below), at the pages indicated.
FIRST- ENERGY OE CEI TE ------ -- --- -- Report of Independent Auditors......................................................... 2 37 37 40 Report of Independent Accountants...................................................... 3 38 -- -- Statements of Income - Three Years Ended December 31, 2002............................. 32 15 16 16 Balance Sheets - December 31, 2002 and 2001............................................ 33 16 17 17 Statements of Capitalization - December 31, 2002 and 2001.............................. 34-37 17-18 18-19 18-19 Statements of Common Stockholders' Equity - Three Years Ended December 31, 2002........ 38 19 20 20 Statements of Preferred Stock - Three Years Ended December 31, 2002.................... 39 19 20 20 Statements of Cash Flows - Three Years Ended December 31, 2002......................... 40 20 21 21 Statements of Taxes - Three Years Ended December 31, 2002.............................. 41 21 22 22 Notes to Financial Statements.......................................................... 42-75 22-36 23-36 23-39
19 3. EXHIBITS - FIRSTENERGY EXHIBIT NUMBER - ------- 3-1 - Articles of Incorporation constituting FirstEnergy Corp.'s Articles of Incorporation, dated September 17, 1996. (September 17, 1996 Form 8-K, Exhibit C) 3-1(a) - Amended Articles of Incorporation of FirstEnergy Corp. (Registration No. 333-21011, Exhibit (3)-1) 3-2 - Regulations of FirstEnergy Corp. (September 17, 1996 Form 8-K, Exhibit D) 3-2(a) - FirstEnergy Corp. Amended Code of Regulations. (Registration No. 333-21011, Exhibit (3)-2) 4-1 - Rights Agreement (December 1, 1997 Form 8-K, Exhibit 4.1) 4-2 - FirstEnergy Corp. to The Bank of New York, Supplemental Indenture, dated November 7, 2001. (2001 Form 10-K, Exhibit 4-2) 10-1 - FirstEnergy Corp. Executive and Director Incentive Compensation Plan, revised November 15, 1999. (1999 Form 10-K, Exhibit 10-1) 10-2 - Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, revised November 15, 1999. (1999 Form 10-K, Exhibit 10-2) 10-3 - Employment, severance and change of control agreement between FirstEnergy Corp. and executive officers. (1999 Form 10-K, Exhibit 10-3) 10-4 - FirstEnergy Corp. Supplemental Executive Retirement Plan, amended January 1, 1999. (1999 Form 10-K, Exhibit 10-4) 10-5 - FirstEnergy Corp. Executive Incentive Compensation Plan. (1999 Form 10-K, Exhibit 10-5) 10-6 - Restricted stock agreement between FirstEnergy Corp. and A. J. Alexander. (1999 Form 10-K, Exhibit 10-6) 10-7 - FirstEnergy Corp. Executive and Director Incentive Compensation Plan. (1998 Form 10-K, Exhibit 10-1) 10-8 - Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, amended February 15, 1999. (1998 Form 10-K, Exhibit 10-2) 10-9 - Restricted stock agreement between FirstEnergy Corp. and A. J. Alexander. (2000 Form 10-K, Exhibit 10-9) 10-10 - Restricted stock agreement between FirstEnergy Corp. and H. P. Burg. (2000 Form 10-K, Exhibit 10-10) 10-11 - Stock option agreement between FirstEnergy Corp. and officers dated November 22, 2000. (2000 Form 10-K, Exhibit 10-11) 10-12 - Stock option agreement between FirstEnergy Corp. and officers dated March 1, 2000. (2000 Form 10-K, Exhibit 10-12) 10-13 - Stock option agreement between FirstEnergy Corp. and director dated January 1, 2000. (2000 Form 10-K, Exhibit 10-13) 10-14 - Stock option agreement between FirstEnergy Corp. and two directors dated January 1, 2001. (2000 Form 10-K, Exhibit 10-14) 20 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) 10-28 Executive and Director Stock Option Agreement dated June 11, 2002. 10-29 Director Stock Option Agreement. 10-30 Executive and Director Executive Incentive Compensation Plan, Amendment dated May 21, 2002. 10-31 Directors Deferred Compensation Plan, Revised Nov. 19, 2002. 10-32 Executive Incentive Compensation Plan 2002. 10-33 - GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries as amended and restated to reflect amendments through June 3, 1999. (1999 Form 10-K, Exhibit 10-V, File No. 1-6047, GPU, Inc.) 10-34 - Form of 1998 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1997 Form 10-K, Exhibit 10-Q, File No. 1-6047, GPU, Inc.) 10-35 - Form of 1999 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1999 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.) 10-36 - Form of 2000 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (2000 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.) 10-37 - Deferred Remuneration Plan for Outside Directors of GPU, Inc. as amended and restated effective August 8, 2000. (2000 Form 10-K, Exhibit 10-O, File No. 1-6047, GPU, Inc.) 21 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.) * 12.1 - Consolidated fixed charge ratios. * 13 - FirstEnergy 2002 Annual Report to Stockholders, as revised. (Only those portions expressly incorporated by reference in this Form 10-K/A are to be deemed "filed" with the SEC.) 21 - List of Subsidiaries of the Registrant at December 31, 2002. * 23 - Consent of Independent Auditors. * 31.1 - Certification letter from chief executive officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. * 31.2 - Certification letter from chief financial officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. * 32 - Certification letter from chief executive officer and chief financial officer, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act. * Indicates revised exhibits included in this Form 10-K/A in electronic format. Reference is made to the original 10-K for the other exhibits filed with it. 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)
22
DATED AS OF FILE REFERENCE EXHIBIT NO ----------- -------------- ---------- 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) 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)) 23 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) 24 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.) 25 (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 26 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 27 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 28 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.) 29 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 30 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.) 31 (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.) 32 (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.) 33 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/A are to be deemed "filed" with the SEC.) 21.1 - List of Subsidiaries of the Registrant at December 31, 2002. (A) 23.1 - Consent of Independent Auditors. (A) 31.1 - Certification letter from chief executive officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. (A) 31.2 - Certification letter from chief financial officer, as adopted pursuant to Section 302 or the Sarbanes-Oxley Act. (A) 32 - Certification letter from chief executive officer and chief financial officer, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act. (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. 34 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). 35 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). 36 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). 37 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). 38 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). 39 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). 4b(83) - May 15, 2002 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/A are to be deemed "filed" with the SEC.) 21.2 - List of Subsidiaries of the Registrant at December 31, 2002. (A) 31.1 - Certification letter from chief executive officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. (A) 31.2 - Certification letter from chief financial officer, as adopted pursuant to Section 302 or the Sarbanes-Oxley Act. (A) 32 - Certification letter from chief executive officer and chief financial officer, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act. (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) 40 (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 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/A are to be deemed "filed" with the SEC.) 41 21.3 - List of Subsidiaries of the Registrant at December 31, 2002. (A) 31.1 - Certification letter from chief executive officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. (A) 31.2 - Certification letter from chief financial officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. (A) 32 - Certification letter from chief executive officer and chief financial officer, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act. (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. (B) REPORTS ON FORM 8-K FIRSTENERGY- FirstEnergy filed twenty-four reports on Form 8-K since September 30, 2002. A report dated October 7, 2002 reported updated cost and schedule estimates associated with efforts to return Davis-Besse Nuclear Power Station to service. A report dated October 31, 2002 reported updated information associated with Davis-Besse restoration efforts. A report dated December 2, 2002 reported the merger of the GPU Employees Savings Plan into the FirstEnergy System Savings Plan. A report dated December 3, 2002 reported updated FirstEnergy 2003 earnings guidance. A report dated December 20, 2002 reported that FirstEnergy subsidiaries would retain ownership of four power plants previously planned to be sold. A report dated January 17, 2003 reported updated information related with efforts to prepare Davis-Besse for a safe and reliable return to service and the updated schedule for JCP&L rate proceedings. A report dated January 21, 2003 reported that the Pennsylvania Supreme Court denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the Pennsylvania Public Utility Commission's order approving the FirstEnergy and GPU merger, let stand the Commonwealth Court's denial of PLR relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. A report dated March 11, 2003 reported updated Davis-Besse information including the installation of the new reactor head on the reactor vessel. A report dated March 17, 2003 reported updated Davis-Besse information, the filing of a $2 billion shelf registration with the SEC and the status of the JCP&L rate proceedings. A report dated March 18, 2003 reported NJBPU audit results of JCP&L restructuring-related deferrals. A report dated April 16, 2003 reported updated Davis-Besse information. A report dated April 18, 2003 reported FirstEnergy's divestiture of its Argentina operations through the abandonment of its investment resulting in a second quarter 2003 charge to net income of $63 million. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003 results and other updated information including Davis-Besse updated ready for restart schedule. A report dated May 9, 2003 reported updated Davis-Besse information and a JCP&L rate proceedings update. A report dated May 9, 2003, reported the filing of the Form 10-K/A Amendment No. 1. A report dated May 22, 2003, reported an agreement to sell FirstEnergy's 20.1% interest in United Kingdom-based Aquila Sterling Limited, the owner of Midlands Electricity. A report dated June 5, 2003 reported updated Davis-Besse information. A report dated June 11, 2003, reported a letter filed with a Pennsylvania Public Utility Commission Administrative Law Judge which voids a prior stipulation. A report dated June 27, 2003, reported JCP&L's signing of a settlement agreement with certain parties in its base rate case proceeding. A report dated July 24, 2003, reported updates to the schedule and cost estimates for Davis-Besse. A reported dated July 25, 2003 reported the New Jersey Board of Public Utilities decision on JCP&L's rate proceedings. A report dated August 5, 2003 reported FirstEnergy's second quarter 2003 earnings results and other information. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements and restatement and reaudit of 2001 CEI and TE financial statements. A report dated August 7, 2003 reported the pending restatement and reaudit of 2000 CEI and TE financial statements. A report dated August 8, 2003 reported a U.S. District Court ruling with respect to the W. H. Sammis Plant under the Clean Air Act. OE OE filed two reports on Form 8-K since March 31, 2003. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements. A report dated August 8, 2003 reported a U.S. District Court ruling with respect to the W. H. Sammis Plant under the Clean Air Act. None. 42 CEI CEI filed thirteen 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. A report dated April 16, 2003 reported updated Davis-Besse information. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003 results and other updated information including Davis-Besse updated ready for restart schedule. A report dated May 9, 2003 reported updated Davis-Besse information. A report dated June 5, 2003 reported updated Davis Besse information. A report dated July 24, 2003, reported updates to the schedule and cost estimates for Davis Besse. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements and restatement and reaudit of 2001 CEI and TE financial statements. A report dated August 7, 2003 reported the pending restatement and reaudit of 2000 CEI and TE financial statements. TE TE filed thirteen 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. A report dated April 16, 2003 reported updated Davis-Besse information. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003 results and other updated information including Davis-Besse updated ready for restart schedule. A report dated May 9, 2003 reported updated Davis-Besse information. A report dated June 5, 2003 reported updated Davis Besse information. A report dated July 24, 2003, reported updates to the schedule and cost estimates for Davis Besse. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements and restatement and reaudit of 2001 CEI and TE financial statements. A report dated August 7, 2003 reported the pending restatement and reaudit of 2000 CEI and TE financial statements. 43 REPORT OF INDEPENDENT AUDITORS ON FINANCIAL STATEMENT SCHEDULES To the Stockholders and Board of Directors of The Cleveland Electric Illuminating Company: Our audits of the consolidated financial statements referred to in our report dated August 18, 2003 appearing in the restated 2002 Annual Report to Shareholders of The Cleveland Electric Illuminating Company (which report and consolidated financial statements are incorporated by reference in this Form 10-K/A) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K/A. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. PricewaterhouseCoopers LLP Cleveland, Ohio August 18, 2003 44 REPORT OF INDEPENDENT AUDITORS ON FINANCIAL STATEMENT SCHEDULES To the Stockholders and Board of Directors of The Toledo Edison Company: Our audits of the consolidated financial statements referred to in our report dated August 18, 2003 appearing in the restated 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/A) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K/A. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. PricewaterhouseCoopers LLP Cleveland, Ohio August 18, 2003 45 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 ====== ========= ====== ====== ======
47 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.................. $ -- $ -- $ -- $ -- $ -- ========= ========= ========= ========= =========
48 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. FIRSTENERGY CORP. Registrant OHIO EDISON COMPANY Registrant THE CLEVELAND ELECTRIC ILLUMINATING COMPANY Registrant THE TOLEDO EDISON COMPANY Registrant /s/Harvey L. Wagner --------------------------------------- Harvey L. Wagner Vice President, Controller and Chief Accounting Officer Date: August 18, 2003 49 EX-12.1 3 l02705aexv12w1.txt EXHIBIT 12.1 . . . EXHIBIT 12.1 FIRSTENERGY CORP. CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 1998 1999 2000 2001 2002 ---------- ---------- ---------- ---------- ---------- RESTATED (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 $ 646,447 $ 552,804 Interest and other charges, before reduction for amounts capitalized ......................................... 608,618 585,648 556,194 591,192 986,756 Provision for income taxes .................................... 321,699 394,827 376,802 474,457 528,694 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 $1,970,657 $2,314,670 ========== ========== ========== ========== ========== FIXED CHARGES AS DEFINED IN REGULATION S-K: Interest expense .............................................. $ 542,819 $ 509,169 $ 493,473 $ 519,131 $ 911,109 Subsidiaries' preferred stock dividend requirements ........... 65,299 76,479 62,721 72,061 75,647 Adjustments to subsidiaries' preferred stock dividends to state on a pre-income tax basis .......................... 43,370 44,829 32,098 43,931 51,799 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 $1,284,971 ========== ========== ========== ========== ========== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES (b) ................................................... 1.77 2.01 2.10 2.21 1.80 ========== ========== ========== ========== ==========
- ---------- (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 4 l02705aexv13.txt EXHIBIT 13 EXHIBIT 13 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 1 REPORT OF INDEPENDENT AUDITORS 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, prior to the revisions described in Notes 2(E) and 8, were audited by other independent auditors who have ceased operations. Those independent auditors expressed an unqualified opinion on those financials statements, in their report dated March 18, 2002. As discussed in Note 2(E) to the consolidated financial statements, the Company changed its method of accounting for goodwill in 2002. As discussed in Note 2(L) and Note 2(M) to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements for the year ended December 31, 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 auditors who have ceased operations. As described in Note 2(E) to the consolidated financial statements, the financial statements have been revised 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. Additionally, as described in Note 8 to the consolidated financial statements, the Company changed the composition of its reportable segments in 2002. We audited the transitional disclosures described in Note 2(E) and the adjustments that were applied to restate the 2001 and 2000 reportable segments disclosures discussed in Note 8. In our opinion, such adjustments to the reportable segments disclosures are appropriate and have been properly applied and 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 transitional disclosures and adjustments to the reportable segments 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, except as to Note 2(L), which is as of May 9, 2003, and Notes 2(M) and 8, which are as of August 18, 2003 2 The following report is a copy of a report previously issued by Arthur Andersen LLP (Andersen). This report has not been reissued by Andersen and Andersen did not consent to the incorporation by reference of this report (as included in this form 10-K/A) into any of the Company's registration statements. As discussed in Note 2(E) to the consolidated financial statements, the Company has revised its consolidated financial statements for the years ended December 31, 2001 and 2000 to include the transitional disclosures required by Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." Additionally, as discussed in Note 8 to the consolidated financial statements, the Company has revised its consolidated financial statements for the years ended December 31, 2001 and 2000 to reflect changes in the composition of its reportable segments in 2002. The Andersen report does not extend to these changes. The revisions to the 2001 and 2000 financial statements related to these transitional disclosures and the revisions that were applied to restate the 2001 and 2000 reportable segments disclosures were reported on by PricewaterhouseCoopers LLP, as stated in their report appearing herein. 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 3 FIRSTENERGY CORP. SELECTED FINANCIAL DATA
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 1999 1998 - -------------------------------- ----------- ----------- ----------- ----------- ----------- RESTATED (SEE NOTES 2(L) AND (M)) (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues ............................................ $12,230,526 $ 7,999,362 $ 7,028,961 $ 6,319,647 $ 5,874,906 ----------- ----------- ----------- ----------- ----------- Income Before Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Changes ..................... $ 640,280 $ 654,946 $ 598,970 $ 568,299 $ 441,396 ----------- ----------- ----------- ----------- ----------- Net Income .......................................... $ 552,804 $ 646,447 $ 598,970 $ 568,299 $ 410,874 ----------- ----------- ----------- ----------- ----------- Basic Earnings per Share of Common Stock: Before Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Change .................... $ 2.19 $ 2.85 $ 2.69 $ 2.50 $ 1.95 After Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Change .............................. $ 1.89 $ 2.82 $ 2.69 $ 2.50 $ 1.82 Diluted Earnings per Share of Common Stock: Before Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Change ..... $ 2.18 $ 2.84 $ 2.69 $ 2.50 $ 1.95 After Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Change .................... $ 1.88 $ 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 ........................................ $34,386,353 $37,351,513 $17,941,294 $18,224,047 $18,192,177 ----------- ----------- ----------- ----------- ----------- Capitalization at December 31: Common Stockholders' Equity ...................... $ 7,050,661 $ 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* .......................... $18,686,388 $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. 4 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. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate," "potential," "expect," "believe," "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), availability and cost of capital, inability of the Davis-Besse Nuclear Power Station to restart (including because of an inability to obtain a favorable final determination from the Nuclear Regulatory Commission) in the fall of 2003, inability to accomplish or realize anticipated benefits from strategic goals, further investigation into the causes of the August 14, 2003, power outage 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. RESTATEMENTS As further discussed in Note 2(M) to the Consolidated Financial Statements, the Company is restating its consolidated financial statements for the year ended December 31, 2002. The revisions principally reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. Transition Cost Amortization As discussed under Regulatory matters in Note 2(D), FirstEnergy's Ohio electric utilities recover transition costs, including regulatory assets, through an approved transition plan filed under Ohio's electric utility restructuring legislation. The plan, which was approved in July 2000, provides for the recovery of costs from January 1, 2001 through a fixed number of kilowatt-hour sales to all customers that continue to receive regulated transmission and distribution service, which is expected to end in 2006 for OE, 2007 for TE and in 2009 for CEI. FirstEnergy, OE, CEI and TE amortize these transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments), but not in the financial statements prepared under generally accepted accounting principles (GAAP). The Ohio electric utilities have revised their amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period, compared with the method previously applied. The change in method results in no change in total amortization of the regulatory assets recovered under the transition period through the end of 2009. 5 After giving effect to the restatement, total transition cost amortization including above market leases) is expected to approximate the following for the years from 2003 through 2009 (in millions). 2003 $685 2004 786 2005 913 2006 378 2007 213 2008 163 2009 44 Above-Market Lease Costs In 1997, FirstEnergy was formed through a merger between OE and Centerior Energy Corporation. The merger was accounted for as an acquisition of Centerior, the parent company of CEI and TE, under the purchase accounting rules of Accounting Principles Board (APB) Opinion No. 16. In connection with the reassessment of the accounting for the transition plan, FirstEnergy reassessed its accounting for the Centerior purchase and determined that above-market lease liabilities should have been recorded at the time of the merger. Accordingly, in 2002, FirstEnergy recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above March 1 market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE recorded an increase in goodwill related to the above March 1 market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional liability would have increased goodwill at the date of the merger. The corresponding impact of the above March 1 market lease liability for the Bruce Mansfield Plant were recorded as regulatory assets because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided under the transition plan. The total above-market lease obligation of $722 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017 (approximately $37 million per year). The additional goodwill has been recorded on a net basis, reflecting amortization that would have been recorded through 2001, when goodwill amortization ceased with the adoption of Statement of Financial Accounting Standard No.SFAS) 142, "Goodwill and Other Intangible Assets". The total above-market lease obligation of $755 million associated with the Bruce Mansfield Plant is being amortized through the end of 2016 (approximately $48 million per year). Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation resulting in no impact to net income. Beginning in 2001, the remaining unamortized regulatory asset would have been included in CEI's and TE's amortization schedules for regulatory assets and amortized through the end of the recovery period - approximately 2009 for CEI and 2007 for TE. FirstEnergy has reflected the net impact of the accounting for these items for the period from the merger in 1997 through 2001 in the 2002 financial statements. The cumulative impact to net income recorded in 2002 related to these prior periods increased net income by $5.9 million in the restated 2002 financial statements and is reflected as a reduction in other operating expenses in the accompanying consolidated statement of income. In addition, the impact increased the following balances in the consolidated balance sheet as of January 1, 2002: 6
INCREASE (DECREASE) (IN THOUSANDS) Goodwill............................ $ 381,780 Regulatory assets................... 636,100 ---------- Total assets........................ $1,017,880 ========== Other current liabilities........... 84,600 Deferred income taxes............... (262,580) Deferred investment tax credits..... (828) Other deferred credits.............. 1,190,800 ---------- Total liabilities................... $1,011,992 ========== Retained earnings................... $ 5,888 ==========
The after-tax effect of the actual 2002 impact of these items decreased net income for the year ended December 31, 2002, by $71 million, or $0.24 per share. The effects of these changes on the Consolidated Statement of Income, Consolidated Balance Sheet and Consolidated Statement of Cash Flows previously reported for December 31, 2002 are described in Note 2(M) to the Consolidated Financial Statements. The adjustments described above are anticipated to result in a decrease in reported net income through 2005 and an increase in net income for the period 2006 through 2017, the end of the lease term for Beaver Valley Unit 2. The schedule below shows the estimated impact on net income of these adjustments for 2003 through 2008.
CHANGE IN REGULATORY LEASE EFFECT ON EFFECT TRANSITION COST ASSET LIABILITY PRE-TAX ON NET YEAR AMORTIZATION AMORTIZATION (A) REVERSAL INCOME INCOME - ---- ------------ ---------------- -------- ------ ------ (in millions) 2003 $(68) $(103) $85 $(86) $(51) 2004 (40) (118) 85 (73) (43) 2005 36 (136) 85 (16) (9) 2006 33 (83) 85 35 20 2007 64 (77) 85 72 43 2008 106 (56) 85 135 80
(a) This represents the additional amortization related to the regulatory assets recognized in connection with the above-market lease for the Bruce Mansfield Plant discussed above. Other Adjustments - FirstEnergy has also included in this restatement certain immaterial adjustments that were not previously recognized in 2002 related to the recognition of a valuation allowance on a tax benefit recognized in 2002 and other adjustments. The impact of these adjustments decreased net income by $11.3 million. The total after-tax effect of the adjustments in this restatement decreased net income for the year ended December 31, 2002, by $76 million, or $0.26 per share as shown below.
INCOME STATEMENT EFFECTS - ------------------------ INCREASE (DECREASE) TRANSITION REVERSAL COST OF LEASE TOTAL AMORTIZATION OBLIGATIONS OTHER ADJUSTMENTS ------------ ----------- -------- ----------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Total revenues ............................ $ -- $ -- $ -- $ -- Fuel and purchased power .................. -- -- (10,700) (10,700) Other operating expenses .................. -- (90,688) 14,800 75,888 Provision for depreciation and amortization 150,474 50,272 -- 200,746 ------------ ----------- -------- ----------- Income before interest and income taxes ... 150,474 40,416 (4,100) 114,158 Net interest charges ...................... -- -- (3,300) (3,300) Income taxes .............................. (30,920) (13,962) 10,500 (34,382) ------------ ----------- -------- ----------- Net income effect ......................... $ 119,554 $ 54,378 $(11,300) $ 76,476 ============ =========== ======== =========== Basic earnings per share effect ........... $ (0.42) $ 0.20 $ (0.04) $ (0.26) ============ =========== ======== =========== Diluted earnings per share effect $ (0.42) $ 0.20 $ (0.04) $ (0.26) ============ =========== ======== ===========
7 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 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 $552.8 million in 2002, compared to $646.4 million in 2001 and $599.0 million in 2000. 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 $404.2 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. 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). 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. (See Note 3 regarding the April 2003 abandonment). Further information on the impact of the changes in accounting related to our divestiture activities is available in the "Change in Previously Reported Income Statement Classifications" 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 change are summarized in the following table: 8 ONE-TIME CHARGES
2002 2001 CHANGE ------ ------ ------ (IN MILLIONS) Investment impairments................................... $100.7 -- $100.7 Pennsylvania deferred energy costs....................... 55.8 -- 55.8 Avon and Emdersa adjustment.............................. 61.0 -- 43.5 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 ------ ------ ------ .......................................................... $310.0 $ 18.0 $274.5 ====== ====== ====== REDUCTION TO EARNINGS PER SHARE OF COMMON STOCK BASIC.................................................. $ 0.76 $ 0.05 $0.65 ====== ====== ====== DILUTED................................................ $ 0.76 $ 0.05 $0.65 ====== ====== ======
Revenues Total revenues increased $4.2 billion in 2002, which included more than $4.6 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: 9
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 ............................. 766.0 101.9 -------- -------- Total Former GPU Companies ........................... 4,548.4 672.3 Intercompany Revenues ................................ (341.9) (38.6) -------- -------- Net Revenue Increase ................................. $4,231.2 $ 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 10 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. 11 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 $3.8 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 $409.9 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 $ 431.0 $ 48.7 Purchased gas (227.9) 266.5 Other operating expenses 102.6 178.2 Depreciation and amortization 75.6 (99.0) General taxes 28.5 (114.0) -------- -------- TOTAL PRE-MERGER COMPANIES 409.9 280.4 -------- -------- FORMER GPU COMPANIES 3,730.0 542.4 INTERCOMPANY EXPENSES (353.9) (32.6) -------- -------- NET EXPENSE INCREASE $3,785.9 $ 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 $352.9 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. 12 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 $102.6 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). The reversal of lease obligations related to the Bruce Mansfield fossil facility and Beaver Valley nuclear facility reduced other operating expenses by $84.8 million in 2002 as compared to 2001. 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 increased $75.6 million in 2002 from the preceding year. This increase resulted from several factors: increased amortization under the Ohio transition plan ($201 million). 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. However, two factors offset a portion of the above increase: 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. 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 $406.6 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 13 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. Discontinued Operations In April 2003, FirstEnergy divested its ownership in GPU Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa) through the abandonment of its shares in the parent company of the Argentina operation. FirstEnergy has reclassified the results of Emdersa for the year ended December 31, 2002, totaling $87.5 million in discontinued operations. Cumulative Effect of Accounting Change In 2001, we adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" resulting in an $8.5 million after-tax charge. (See Note 2J) 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 $938 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 $103.7 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 (232.4) (344.1) ------- ------- Income Before Interest and Income Taxes (297.1) 227.7 ------- ------- Net interest charges (131.3) (16.8) Income taxes (62.1) 132.7 ------- ------- Net Income Change $(103.7) $ 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 14 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 $232.4 million decrease in expenses primarily resulted from three major factors: a $190.5 million decrease in purchased power, a $111.6 million reduction in other operating expenses and a $58.9 million increase 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. Higher depreciation and amortization resulted from $201 million higher incremental transition costs partially offset by $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 15 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) $ 1,059 $ 1,551 Working capital and other 405 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: 16
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 - ----------------------------- --------- ----------- ----- ----- SOURCES (USES) (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. 17
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). in the 2001 merger with GPU. On April 18, 2003, we divested our ownership interest in Emdersa, our Argentina operations, resulting in a charge of $87.5 million in the restated year ended December 31, 2002 Consolidated Statement of Income as "Discontinued Operations (See Note 2M). On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." On July 25, 2003, Standard & Poor's (S&P) issued comments on FirstEnergy's debt ratings in light of the latest extension of the Davis-Besse outage and the NJBPU decision on the JCP&L rate case. S&P noted that additional costs from the Davis-Besse outage extension, the NJBPU ruling on recovery of deferred energy costs and additional capital investments required to improve reliability in the New Jersey shore communities will adversely affect FirstEnergy's cash flow and deleveraging plans. S&P noted that it continues to assess FirstEnergy's plans to determine if projected financial measures are adequate to maintain its current rating. On August 7, 2003, S&P affirmed its "BBB" corporate credit rating for FirstEnergy. However, S&P stated that although FirstEnergy generates substantial free cash, that its strategy for reducing debt had deviated substantially from the one presented to S&P around the time of the GPU merger when the current rating was assigned. S&P further noted that their affirmation of FirstEnergy's corporate credit rating was based on the assumption that FirstEnergy would take appropriate steps quickly to maintain its investment grade ratings including the issuance of equity and possible sale of assets. Key issues being monitored by S&P included reaudit of CEI and TE by PricewaterhouseCoopers LLP, restart of Davis-Besse, FirstEnergy's liquidity position, its ability to forecast provider-of-last-resort load and the performance of its hedged portfolio, and capture of merger synergies. 18 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 19 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: 20
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. 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 21 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 EUOC 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. 22 Optimizing the Use of Assets Upon completion of its merger with GPU, FirstEnergy accepted an October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase Avon, FirstEnergy's wholly owned holding company for Midlands Electricity plc, for $2.1 billion (including the assumption of $1.7 billion of debt). The transaction closed on May 8, 2002 and reflected the March 2002 modification of Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest in Avon for approximately $1.9 billion (including the assumption of $1.7 billion of debt). Proceeds to FirstEnergy included $155 million in cash and a note receivable for approximately $87 million (representing the present value of $19 million per year to be received over six years beginning in 2003) from Aquila for its 79.9 percent interest. FirstEnergy and Aquila together own all of the outstanding shares of Avon through a jointly owned subsidiary, with each company having an ownership voting interest. Originally, in accordance with applicable accounting guidance, the earnings of those foreign operations were not recognized in current earnings from the date of the GPU acquisition. However, as a result of the decision to retain an ownership interest in Avon in the quarter ended March 31, 2002, EITF Issue No. 90-6, "Accounting for Certain Events Not Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be Sold" required FirstEnergy to reallocate the purchase price of GPU based on amounts as of the purchase date as if Avon had never been held for sale, including reversal of the effects of having applied EITF Issue No. 87-11, to the transaction. The effect of reallocating the purchase price and reversal of the effects of EITF Issue No. 87-11, including the allocation of capitalized interest, has been reflected in the Consolidated Statement of Income for the six months ended June 30, 2002 by reclassifying certain revenue and expense amounts related to activity during the quarter ended March 31, 2002 to their respective income statement classifications for the six-month 2002 period. See Note 1 for the effects of the change in classification. In the fourth quarter of 2002, FirstEnergy recorded a $50 million charge to reduce the carrying value of its remaining 20.1 percent interest. On May 22, 2003, FirstEnergy announced it reached an agreement to sell its 20.1 percent interest in Avon to Scottish and Southern Energy plc; that agreement also includes Aquila's 79.9 percent interest. Under terms of the agreement, Scottish and Southern will pay FirstEnergy and Aquila an aggregate $70 million (FirstEnergy's share would be approximately $14 million). Midland's debt will remain with that company. FirstEnergy also recognized in the second quarter of 2003 an impairment of $12.6 million ($8.2 million net of tax) related to the carrying value of the note FirstEnergy had with Aquila from the initial sale of a 79.9 percent interest in Avon that occurred in May 2002. After receiving the first annual installment payment of $19 million in May 2003, FirstEnergy sold the remaining balance of its note receivable in a secondary market and received $63.2 million in proceeds on July 28, 2003. 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 EUOC's 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: - allowing the EUOC's electric customers to select their generation suppliers; - establishing PLR obligations to non-shopping customers in the EUOC's service areas; - allowing recovery of potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; - itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; - deregulating the EUOC's electric generation businesses; and - continuing regulation of the EUOC's transmission and distribution systems. 23 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 - ------- ---- (IN MILLIONS) OE $1,848.7 CEI 1,191.8 TE 578.2 Penn 156.9 JCP&L 3,199.0 Met-Ed 1,179.1 Penelec 599.7 - ------------------------------------- Total $8,753.4 =====================================
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. JCP&L submitted two rate filings with the NJBPU in August 2002. 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. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision which reduces JCP&L's annual revenues by approximately $62 million effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5 percent on JCP&L's rate base for the next 6 to 12 months. During that period, JCP&L will initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75 percent or decrease it to 9.25 percent, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The revenue decrease in the decision consists of a $223 million decrease in the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC charge. The MTC would allow for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $152.5 million. JCP&L also announced on July 25, 2003 that it is reviewing the NJBPU decision and will decide on its appropriate course of action, which could include filing an appeal for reconsideration with the NJBPU and possibly an appeal to the Appellate Division of the Superior Court of New Jersey. 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 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 24 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 on-peak PLR obligation through 2004 and a portion of 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. 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 during that period. On April 2, 2003, the PPUC remanded the merger savings issue to the Office of Administrative Law for hearings and directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court's order on the Settlement Stipulation by May 2, 2003 and for the other parties to file their responses to the Met-Ed and Penelec position paper by June 2, 2003. In summary, the Met-Ed and Penelec position paper essentially stated the following: - Because no stay of the PPUC's June 2001 order approving the Settlement Stipulation was issued or sought, the Stipulation remained in effect until the Pennsylvania Supreme Court denied all appeal applications in January 2003, - As of January 16, 2003, the Supreme Court's Order became final and the portions of the PPUC's June 2001 Order that were inconsistent with the Supreme Court's findings were reversed, - The Supreme Court's finding effectively amended the Stipulation to remove the PLR cost recovery and deferral provisions and reinstated the GENCO Code of Conduct as a merger condition, and - All other provisions included in the Stipulation unrelated to these three issues remain in effect. The other parties' responses included significant disagreement with the position paper and disagreement among the other parties themselves, including the Stipulation's original signatory parties. Some parties believe that no portion of the Stipulation has survived the Commonwealth Court's Order. Because of these disagreements, Met-Ed and Penelec filed a letter on June 11, 2003 with the Administrative Law Judge assigned to the remanded case voiding the Stipulation in its entirety pursuant to the termination provisions. They believe this will significantly simplify the issues in the pending action by reinstating Met-Ed's and Penelec's Restructuring Settlement previously approved by the PPUC. In addition, they have agreed to voluntarily continue certain Stipulation provisions including funding for energy and demand side response programs and to cap distribution rates at current levels through 2007. This voluntary distribution rate cap is contingent upon a finding that Met-Ed and Penelec have satisfied the "public interest" test applicable to mergers and that any rate impacts of merger savings will be dealt with in a subsequent rate case. Based upon this letter, Met-Ed and Penelec believe that the remaining issues before the Administrative Law Judge are the appropriate treatment of merger savings issues and whether their accounting and related tariff modifications are consistent with the Court Order. 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 25 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 Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by 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, FirstEnergy has 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. FirstEnergy is also accelerating maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy 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. FirstEnergy anticipates that the unit will be ready for restart in the fall of 2003. 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 FirstEnergy's plans to reduce post-merger debt levels FirstEnergy believes 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 for the expected length of the outage. 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) 26 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. 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 civil complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning March 15, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, may have a material adverse impact on the Company's financial condition and results or operations. Management is unable to predict the ultimate outcome of this matter. 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 27 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. It is FirstEnergy's understanding that, as of August 18, 2003, five individual described herein shareholder-plaintiffs have filed separate complaints against FirstEnergy Corp. alleging various securities law violations in connection with the restatement of earnings described herein. Most of these complaints have not yet been officially served on the Company. Moreover, FirstEnergy is still reviewing the suits that have been served in preparation for a responsive pleading. FirstEnergy is however, aware that in each case, the plaintiffs are seeking certification from the court to represent a class of similarly situated shareholders. Power Outage On August 14, 2003, eight states and southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. The cause of the outage has not been determined. Having restored service to its customers, FirstEnergy is now in the process of accumulating data and evaluating the status of its electrical system prior to and during the outage event and would expect that the same effort Is under way at utilities and regional transmission operators across the region. As of August 18, 2003, the following facts about FirstEnergy's system were known. Early in the afternoon of August 14, hours before the event, Unit 5 of the Eastlake Plant in Eastlake, Ohio tripped off. Later in the afternoon, three FirstEnergy transmission lines and one owned by American Electric Power and FirstEnergy tripped out of service. The Midwest Independent System Operator (MISO), which oversees the regional transmission grid, indicated that there were a number of other transmission line trips in the region outside of FirstEnergy's system. FirstEnergy customers experienced no service interruptions resulting from these conditions. Indications to FirstEnergy were that the Company's system was stable. Therefore, no isolation of FirstEnergy's system was called for. In addition, FirstEnergy determined that its computerized system for monitoring and controlling its transmission and generation system was operating, but the alarm screen function was not. However, MISO's monitoring system was operating properly. FirstEnergy believes that extensive data needs to be gathered and analyzed in order to determine with any degree of certainty the circumstances that led to the outage. This is a very complex situation, far broader than the power line outages FirstEnergy experienced on its system. From the preliminary data that has been gathered, FirstEnergy believes that the transmission grid in the Eastern Interconnection, not just within FirstEnergy's system, was experiencing unusual electrical conditions at various times prior to the event. These included unusual voltage and frequency fluctuations and load swings on the grid. FirstEnergy is committed to working with the North American Electric Reliability Council and others involved to determine exactly what events in the entire affected region led to the outage. There is no timetable as to when this entire process will be completed. It is, however, expected to last several weeks, at a minimum. 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 28 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 KWH billion 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 ----------------------------------------------------------------------------------- RESTATED ----------------------------------------------------------------------- (SEE NOTES 2(L) AND 2(M)) --------------------------------------------------------------------------------- (IN MILLIONS) Total before adjustment $12,515 $10,378 Adjustment (268) (268) ------------------------------------------------------------------------------------- Total as reported $12,247 $10,110 ====================================================================================
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 - $8.8 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: 29 - Net energy generated or purchased for retail load - Losses of energy over transmission and distribution lines - Mix of KWH usage by residential, commercial and industrial customers - 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 ------------------------------------------------------------------------------------------------
30 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 The regulators in the jurisdictions that the Companies operate in do not provide recovery at goodwill. As a result, no amortization has been recorded subsequent to the adoption of SFAS 142. 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 $6.3 billion of goodwill that primarily relates to our regulated services segment. 31 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 $602 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 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 $175 million increase to income ($102 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 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. 32 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 (FirstEnergy's 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. 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 FirstEnergy 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 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 $11.6 million. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and is effective at the beginning of the first interim period beginning after June 15, 2003 (FirstEnergy's third quarter of 2003) for all other financial instruments. FirstEnergy did not enter into or modify any financial instruments within the scope of SFAS 150 during June 2003. Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy expects to classify as debt the preferred stock of consolidated subsidiaries subject to mandatory redemptions with a carrying value of approximately $19 million as of June 30, 2003. Subsidiary preferred dividends on FirstEnergy's Consolidated Statements of Income are currently included in net interest charges. Therefore, the application of SFAS 150 will not require the reclassification of such preferred dividends to net interest charges. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence in a contract of a general index, such as the Consumer Price Index, would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. FirstEnergy is currently assessing the new guidance and has not yet determined the impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus will be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. FirstEnergy is currently assessing the new EITF consensus and has not yet determined the impact on its financial position or results of operations following adoption. 33 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 - --------------------------------------------------------------------------------------------------------------------- RESTATED (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) REVENUES: Electric utilities ......................................... $ 9,165,805 $ 5,729,036 $ 5,421,668 Unregulated businesses ..................................... 3,064,721 2,270,326 1,607,293 ------------ ----------- ----------- Total revenues ......................................... 12,230,526 7,999,362 7,028,961 ------------ ----------- ----------- EXPENSES: Fuel and purchased power ................................... 3,662,910 1,421,525 1,110,845 Purchased gas .............................................. 592,116 820,031 553,548 Other operating expenses (Note 2(M)) ....................... 3,888,909 2,727,794 2,378,296 Provision for depreciation and amortization (Note 2(M)) .... 1,305,843 889,550 933,684 General taxes .............................................. 650,329 455,340 547,681 ------------ ----------- ----------- Total expenses ......................................... 10,100,107 6,314,240 5,524,054 ------------ ----------- ----------- INCOME BEFORE INTEREST AND INCOME TAXES ....................... 2,130,419 1,685,122 1,504,907 ------------ ----------- ----------- NET INTEREST CHARGES: Interest expense ........................................... 910,272 519,131 493,473 Capitalized interest ....................................... (24,474) (35,473) (27,059) Subsidiaries' preferred stock dividends .................... 75,647 72,061 62,721 ------------ ----------- ----------- Net interest charges ................................... 961,445 555,719 529,135 ------------ ----------- ----------- INCOME TAXES .................................................. 528,694 474,457 376,802 ------------ ----------- ----------- INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGES ............................... 640,280 654,946 598,970 ------------ ----------- ----------- Discontinued operations .................................... (87,476) -- -- Cumulative effect of accounting change (net of income tax benefit of $5,839,000) (Note 2(J)) ............ -- (8,499) -- ------------ ----------- ----------- NET INCOME .................................................... $ 552,804 $ 646,447 $ 598,970 ============ =========== =========== BASIC EARNINGS PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change .................................... $ 2.19 $ 2.85 $ 2.69 Discontinued operations (Note 2(M)) ........................ (0.30) -- -- Cumulative effect of accounting change (Note 2(J)) ......... -- (.03) -- ------------ ----------- ----------- Net income ................................................. $ 1.89 $ 2.82 $ 2.69 ============ =========== =========== WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING ........... 293,194 229,512 222,444 ============ =========== =========== DILUTED EARNINGS PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change .................................... $ 2.18 $ 2.84 $ 2.69 Discontinued operations (Note 2(M)) ........................ (0.30) -- -- Cumulative effect of accounting change (Note 2(J)) ......... -- (.03) -- ------------ ----------- ----------- Net income ................................................. $ 1.88 $ 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. 34 FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2002 2001 - --------------------------------------------------------------------------------------------------------------- RESTATED (SEE NOTE 2(M)) (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) ............................ 469,606 473,550 Materials and supplies, at average cost- Owned .................................................................. 253,047 256,516 Under consignment ...................................................... 174,028 141,002 Prepayments and other .................................................... 203,630 336,610 ----------- ----------- 2,450,098 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 ............................. 8,552,927 8,161,022 ----------- ----------- 11,819,297 11,820,727 Construction work in progress ............................................ 859,016 607,702 ----------- ----------- 12,678,313 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 2(I)) .......................................... -- 273,542 Other .................................................................... 918,874 898,311 ----------- ----------- 3,325,632 3,630,564 ----------- ----------- DEFERRED CHARGES: Regulatory assets ........................................................ 8,753,401 8,912,584 Goodwill ................................................................. 6,278,072 5,600,918 Other (Note 2I) .......................................................... 900,837 858,273 ----------- ----------- 15,932,310 15,371,775 ----------- ----------- $34,386,353 $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 ......................................................... 906,468 704,184 Accrued taxes ............................................................ 455,121 418,555 Other .................................................................... 1,093,815 1,064,763 ----------- ----------- 5,251,043 4,669,457 ----------- ----------- LIABILITIES RELATED TO ASSETS PENDING SALE (NOTE 3) ......................... -- 2,954,753 ----------- ----------- CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholders' equity .............................................. 7,050,661 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 5(F)) 409,867 529,450 Long-term debt ........................................................... 10,872,216 11,433,313 ----------- ----------- 18,686,388 19,906,962 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes ........................................ 2,069,682 2,684,219 Accumulated deferred investment tax credits .............................. 236,184 260,532 Nuclear plant decommissioning costs ...................................... 1,243,558 1,201,599 Power purchase contract loss liability ................................... 3,136,538 3,566,531 Retirement benefits ...................................................... 1,564,930 838,943 Other .................................................................... 2,198,030 1,268,517 ----------- ----------- 10,448,922 9,820,341 ----------- ----------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 4 and 7) ................... ----------- ----------- $34,386,353 $37,351,513 =========== ===========
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. 35 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION
AS OF DECEMBER 31, 2002 2001 - ---------------------------------------------------------------------------------------------------- RESTATED (SEE NOTE 2(M)) (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) ............... (656,148) (169,003) Retained earnings (Note 5A) .................................. 1,634,981 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 .......................... 7,050,661 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 ========== ========== ======= -------- --------
36 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
AS OF DECEMBER 31, 2002 2001 - ----------------------------------------------------------------------------------------------------------------------------- RESTATED (SEE NOTE 2(M)) (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 ========== ========== ======== -------- --------
37 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 - ------------------------------------------------------------------------------------------------------------------------------ AS OF DECEMBER 31, 2002 2001 2002 2001 -------- ---------- ---------- ---------- Ohio Edison Co. - Due 2002-2007 ................. 8.02% $230,000 $ 509,265 7.66% $ 186,549 $ 231,907 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 -------- ---------- ---------- ---------- Cleveland Electric Illuminating Co. - Due 2002-2007 ................. 8.97% 400,000 595,000 5.74% 680,175 713,205 Due 2008-2012 ................. 6.86% 125,000 125,000 7.43% 151,610 151,610 Due 2013-2017 ................. -- -- -- 7.88% 300,000 378,700 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 -------- ---------- ---------- ---------- Toledo Edison Co. - Due 2002-2007 ................. 7.90% 178,725 179,125 6.19% 229,700 258,700 Due 2008-2012 ................. -- -- -- -- -- -- 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 -------- ---------- ---------- ---------- Pennsylvania Power Co. - Due 2002-2007 ................. 7.19% 79,370 80,344 2.99% 10,300 10,300 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 -------- ---------- ---------- ---------- Jersey Central Power & Light Co. - Due 2002-2007 ................. 6.90% 442,674 541,260 5.60% 241,135 150,000 Due 2008-2012 ................. 7.13% 5,040 5,040 5.39% 52,273 -- Due 2013-2017 ................. 7.10% 12,200 12,200 6.01% 176,592 -- Due 2018-2022 ................. 8.62% 76,586 170,000 -- -- -- Due 2023-2027 ................. 7.37% 365,000 365,000 -- -- -- Due 2028-2032 ................. -- -- -- -- -- -- Due 2033-2037 ................. -- -- -- -- -- -- Due 2038-2042 ................. -- -- -- -- -- -- -------- ---------- ---------- ---------- Total-Jersey Central ............. 901,500 1,093,500 470,000 150,000 -------- ---------- ---------- ---------- Metropolitan Edison Co. - Due 2002-2007 ................. 6.71% 202,175 262,175 5.79% 150,000 100,000 Due 2008-2012 ................. 6.00% 6,525 6,525 -- -- -- Due 2013-2017 ................. -- -- -- -- -- -- Due 2018-2022 ................. 7.86% 88,500 88,500 -- -- -- Due 2023-2027 ................. 7.55% 133,690 133,690 -- -- -- Due 2028-2032 ................. -- -- -- -- -- -- Due 2033-2037 ................. -- -- -- -- -- -- Due 2038-2042 ................. -- -- -- -- -- -- -------- ---------- ---------- ---------- Total-Metropolitan Edison ........ 430,890 490,890 150,000 100,000 -------- ---------- ---------- ----------
LONG-TERM DEBT (NOTE 5G) (INTEREST RATES REFLECT WEIGHTED AVERAGE RATES) (IN THOUSANDS) - ------------------------------------------------------------------------------------------------------------- UNSECURED NOTES TOTAL - ------------------------------------------------------------------------------------------------------------- AS OF DECEMBER 31, 2002 2001 2002 2001 -------- -------- ----------- ----------- RESTATED (SEE NOTE 2(M)) Ohio Edison Co. - Due 2002-2007 ................. 4.17% $441,725 $441,725 Due 2008-2012 ................. -- -- -- Due 2013-2017 ................. -- -- -- Due 2018-2022 ................. -- -- -- Due 2023-2027 ................. -- -- -- Due 2028-2032 ................. -- -- -- Due 2033-2037 ................. -- -- -- -------- -------- ----------- ----------- Total-Ohio Edison ................ 441,725 441,725 $ 1,524,179 $ 1,848,802 -------- -------- ----------- ----------- Cleveland Electric Illuminating Co. - Due 2002-2007 ................. 5.58% 27,700 27,700 Due 2008-2012 ................. -- -- -- Due 2013-2017 ................. 6.00% 78,700 -- Due 2018-2022 ................. -- -- -- Due 2023-2027 ................. -- -- -- Due 2028-2032 ................. -- -- -- Due 2033-2037 ................. -- -- -- -------- -------- ----------- ----------- Total-Cleveland Electric ......... 106,400 27,700 2,308,688 2,506,718 -------- -------- ----------- ----------- Toledo Edison Co. - Due 2002-2007 ................. 4.83% 91,100 226,130 Due 2008-2012 ................. 10.00% 760 760 Due 2013-2017 ................. -- -- -- Due 2018-2022 ................. -- -- -- Due 2023-2027 ................. -- -- -- Due 2028-2032 ................. -- -- -- Due 2033-2037 ................. -- -- -- -------- -------- ----------- ----------- Total-Toledo Edison .............. 91,860 226,890 729,936 889,166 -------- -------- ----------- ----------- Pennsylvania Power Co. - Due 2002-2007 ................. 4.39% 19,700 5,200 Due 2008-2012 ................. -- -- -- Due 2013-2017 ................. -- -- -- Due 2018-2022 ................. -- -- -- Due 2023-2027 ................. -- -- -- Due 2028-2032 ................. -- -- -- -------- -------- ----------- ----------- Total-Penn Power ................. 19,700 5,200 251,520 252,494 -------- -------- ----------- ----------- Jersey Central Power & Light Co. - Due 2002-2007 ................. 7.69% 93 107 Due 2008-2012 ................. 7.69% 134 134 Due 2013-2017 ................. 7.69% 193 193 Due 2018-2022 ................. 7.69% 280 280 Due 2023-2027 ................. 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 ............. 2,984 2,998 1,374,484 1,246,498 -------- -------- ----------- ----------- Metropolitan Edison Co. - Due 2002-2007 ................. 7.69% 185 214 Due 2008-2012 ................. 7.69% 267 267 Due 2013-2017 ................. 7.69% 387 387 Due 2018-2022 ................. 7.69% 560 560 Due 2023-2027 ................. 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 ........ 5,968 5,997 586,858 596,887 -------- -------- ----------- -----------
38 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 - --------------------------------------------------------------------------------------------------------------------------- AS OF DECEMBER 31, 2002 2001 2002 2001 ---------- ---------- ---------- ---------- RESTATED (SEE NOTE 2(M)) Pennsylvania Electric Co. - Due 2002-2007 6.13% $ 3,905 $ 4,110 -- $ -- $ -- Due 2008-2012 5.35% 24,310 24,310 -- -- -- Due 2013-2017 -- -- -- -- -- -- Due 2018-2022 5.80% 20,000 20,000 -- -- -- Due 2023-2027 6.05% 25,000 25,000 -- -- -- Due 2028-2032 -- -- -- -- -- -- Due 2033-2037 -- -- -- -- -- -- Due 2038-2042 -- -- -- -- -- -- ---------- ---------- ---------- ---------- Total-Pennsylvania Electric 73,215 73,420 -- -- ---------- ---------- ---------- ---------- FirstEnergy Corp. - Due 2002-2007 -- -- -- -- -- -- Due 2008-2012 -- -- -- -- -- -- Due 2013-2017 -- -- -- -- -- -- Due 2018-2022 -- -- -- -- -- -- Due 2023-2027 -- -- -- -- -- -- Due 2028-2032 -- -- -- -- -- -- ---------- ---------- ---------- ---------- Total-FirstEnergy -- -- -- -- ---------- ---------- ---------- ---------- OES Fuel -- -- -- -- 81,515 AFN Finance Co. No. 1 -- -- -- -- 15,000 AFN Finance Co. No. 3 -- -- -- -- 4,000 Bay Shore Power -- -- 6.24% 143,200 145,400 MARBEL Energy Corp. -- -- -- -- -- Facilities Services Group -- -- 4.86% 13,205 15,735 FirstEnergy Generation -- -- -- -- -- FirstEnergy Properties -- -- 7.89% 9,679 9,902 Warrenton River Terminal -- -- 5.25% 634 776 GPU Capital* -- -- -- -- -- GPU Power -- -- 7.14% 174,760 239,373 ---------- ---------- ---------- ---------- Total $2,833,631 $3,561,475 $3,688,090 $3,653,701 ========== ========== ========== ========== Capital lease obligations ................................................................................................. Net unamortized premium on debt* .......................................................................................... Long-term debt due within one year*........................................................................................ Total long-term debt* ..................................................................................................... TOTAL CAPITALIZATION* ..................................................................................................... - ---------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT (INTEREST RATES REFLECT WEIGHTED AVERAGE RATES) (CONT'D) (IN THOUSANDS) - ----------------------------------------------------------------------------------------------------------------------- UNSECURED NOTES TOTAL - ----------------------------------------------------------------------------------------------------------------------- AS OF DECEMBER 31, 2002 2001 2002 2001 ---------- ---------- -------------- -------------- Pennsylvania Electric Co. - Due 2002-2007 5.86% $ 133,093 $ 183,107 Due 2008-2012 6.55% 135,134 135,134 Due 2013-2017 7.69% 193 193 Due 2018-2022 6.63% 125,280 125,280 Due 2023-2027 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 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 AFN Finance Co. No. 1 -- -- -- -- 15,000 AFN Finance Co. No. 3 -- -- -- -- 4,000 Bay Shore Power -- -- -- 143,200 145,400 MARBEL Energy Corp. -- -- 569 -- 569 Facilities Services Group -- -- -- 13,205 15,735 FirstEnergy Generation 5.00% 15,000 -- 15,000 -- FirstEnergy Properties -- -- -- 9,679 9,902 Warrenton River Terminal -- -- -- 634 776 GPU Capital* 5.78% 101,467 1,629,582 101,467 1,629,582 GPU Power 11.87% 67,372 56,048 242,132 295,421 ---------- ---------- -------------- -------------- Total $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* ........................................................... $ 18,686,388 $ 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. 39 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (Restated)
ACCUMULATED OTHER OTHER COMPREHENSIVE NUMBER PAR PAID-IN COMPREHENSIVE INCOME OF SHARES VALUE CAPITAL INCOME (LOSS) ------------- ------------- ------------- ------------- ------------- (DOLLARS IN THOUSANDS) Balance, January 1, 2000 ................... 232,454,287 $ 23,245 $ 3,722,375 $ (195) Net income .............................. $ 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 Cash dividends on common stock .......... Balance, December 31, 2000 ................. 224,531,580 22,453 3,531,821 593 GPU acquisition ......................... 73,654,696 7,366 2,586,097 Net income .............................. $ 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 adjust- ments, 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 Cash dividends on common stock .......... Balance, December 31, 2001 ................. 297,636,276 29,764 6,113,260 (169,003) Net income .............................. $ 552,804 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 $(4,266,000) of income taxes .......... (5,269) (5,269) Unrealized currency translation adjust- ments ................................. (91,448) (91,448) ------------- Comprehensive income .................... $ 65,659 ============= Stock options exercised ................. (8,169) Allocation of ESOP shares ............... 15,250 Cash dividends on common stock .......... Balance, December 31, 2002 ................. 297,636,276 $ 29,764 $ 6,120,341 $ (656,148) ============= ============= ============= ===========
UNALLOCATED ESOP RETAINED COMMON EARNINGS STOCK ------------- ------------- Balance, January 1, 2000 ................... $ 945,241 $ (126,776) Net income .............................. 598,970 Minimum liability for unfunded retirement benefits, net of $85,000 of income taxes ............... Unrealized gain on investment in securities available for sale ......... Comprehensive income .................... Reacquired common stock ................. Allocation of ESOP shares ............... 15,044 Cash dividends on common stock .......... (334,220) ------------- Balance, December 31, 2000 ................. 1,209,991 (111,732) GPU acquisition ......................... Net income .............................. 646,447 Minimum liability for unfunded retirement benefits, net of $(182,000) of income taxes ................................. Unrealized loss on derivative hedges, net of $(116,521,000) of income taxes ..... Unrealized gain on investments, net of $56,000 of income taxes ............... Unrealized currency translation adjust- ments, net of $(1,000) of income taxes Comprehensive income .................... Reacquired common stock ................. Allocation of ESOP shares ............... 14,505 Cash dividends on common stock .......... (334,633) ------------- Balance, December 31, 2001 ................. 1,521,805 (97,227) Net income .............................. 552,804 Minimum liability for unfunded retirement benefits, net of $(316,681,000) of income taxes .......................... Unrealized gain on derivative hedges, net of $37,458,000 of income taxes ........ Unrealized loss on investments, net of $(4,266,000) of income taxes .......... Unrealized currency translation adjust- ments ................................. Comprehensive income .................... Stock options exercised ................. Allocation of ESOP shares ............... 18,950 Cash dividends on common stock .......... (439,628) ------------- Balance, December 31, 2002 ................. $ 1,634,981 (78,277) ============= =============
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 40 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. 41 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 - -------------------------------- ----------- ----------- ----------- (SEE NOTES 2 (L) AND (M)) (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income...................................................... $ 552,804 $ 646,447 $ 598,970 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization................ 1,305,843 889,550 933,684 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................................. 56,732 31,625 (79,429) Investment tax credits, net................................ (28,325) (22,545) (30,732) Cumulative effect of accounting change..................... -- 14,338 -- Discontinued Operations (See Note 2(M)).................... 87,476 -- -- Receivables................................................ (85,307) 53,099 (150,520) Materials and supplies..................................... (29,557) (50,052) (29,653) Accounts payable........................................... 220,762 (84,572) 118,282 Deferred lease costs....................................... (84,800) -- -- Other (Note 9)............................................. 168,701 (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 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. 42 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF TAXES
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 200O - -------------------------------- ----------- ----------- ----------- RESTATED (SEE NOTE 2(M)) (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...................................................... $ 326,417 $ 375,108 $ 467,045 State........................................................ 104,866 84,322 19,918 Foreign...................................................... 20,624 108 -- ----------- ----------- ----------- 451,908 459,538 486,963 ----------- ----------- ----------- Deferred, net- Federal...................................................... 81,934 37,888 (60,831) State........................................................ 7,759 (6,177) (18,598) Foreign...................................................... 13,600 (86) -- ----------- ----------- ----------- 103,293 31,625 (79,429) ----------- ----------- ----------- Investment tax credit amortization.............................. (26,507) (22,545) (30,732) ----------- ----------- ----------- Total provision for income taxes......................... $ 528,694 $ 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................... $1,081,498 $ 1,115,065 $ 975,772 =========== =========== =========== Federal income tax expense at statutory rate.................... $ 390,273 $ 341,520 Increases (reductions) in taxes resulting from- $ 378,524 Amortization of investment tax credits....................... (26,507) (22,545) (30,732) State income taxes, net of federal income tax benefit........ 73,220 50,794 1,133 Amortization of tax regulatory assets........................ 29,296 30,419 38,702 Amortization of goodwill..................................... -- 18,416 18,420 Preferred stock dividends.................................... 13,634 19,733 18,172 Valuation reserve for tax benefits........................... 48,587 -- -- Other, net................................................... 11,440 (18,472) (10,413) ----------- ----------- ----------- Total provision for income taxes......................... $ 528,694 $ 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................................. 1,408,232 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) -- Above market leases........................................... (490,698) -- -- Other (Notes 2 and 9)......................................... (397,506) (323,696) (37,724) ----------- ----------- ----------- Net deferred income tax liability**.................... $2,069,682 $ 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. 43 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 ======= ======= =======
44 (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 - ------------------------------------------- -------- -------- RESTATED (SEE NOTES 2(L) AND 2(M)) (IN MILLIONS) Total before adjustment $12,499 $10,368 Adjustment (268) (268) ------- -------- Total as reported $12,231 $10,100 ======= ========
(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: - allowing the Companies' electric customers to select their generation suppliers; - establishing provider of last resort (PLR) obligations to customers in the Companies' service areas; - allowing recovery of potentially stranded investment (or transition costs); - itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; - deregulating the Companies' electric generation businesses; and 45 - 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 (see Note 2(M) for consideration of above market 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 46 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 (see Note 13) 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. 47 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 $7,740 CEI 1,406 6,510 TE 559 2,862 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: 48
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 $602 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 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 $1.243 billion. 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 $175 million increase to income ($102 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 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. 49 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 -------- -------- -------- RESTATED (SEE NOTE 2(M)) (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Reported net income.............................. $552,804 $646,447 $598,970 Goodwill amortization (net of tax)............... -- 54,584 54,138 -------- -------- -------- Adjusted net income.............................. $552,804 $701,031 $653,108 ======== ======== ======== Basic earnings per common share: Reported earnings per share................... $1.89 $2.82 $2.69 Goodwill amortization......................... -- 0.23 0.25 -------- -------- -------- Adjusted earnings per share................... $1.89 $3.05 $2.94 ======== ======== ======== Diluted earnings per common share: Reported earnings per share................... $1.88 $2.81 $2.69 Goodwill amortization......................... -- 0.23 0.24 -------- -------- -------- Adjusted earnings per share................... $1.88 $3.04 $2.93 ======== ======== ========
The net change of $677 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. 50
2002 2001 2000 -------- -------- -------- RESTATED (SEE NOTE 2(M) (IN THOUSANDS) Net Income, as reported $552,804 $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 $544,145 $642,724 $597,378 -------- -------- -------- Earnings Per Share of Common Stock - Basic As Reported $ 1.89 $ 2.82 $ 2.69 Adjusted $ 1.86 $ 2.80 $ 2.69 Diluted As Reported $ 1.88 $ 2.81 $ 2.69 Adjusted $ 1.85 $ 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. 51 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, 52 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. 53 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. 54 Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:
2002 2001 -------- -------- RESTATED (SEE NOTE 2(M)) (IN MILLIONS) Regulatory transition charge $7,795.7 $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 $8,753.4 $8,912.6 -------- --------
(L) CHANGE IN INCOME STATEMENT CLASSIFICATIONS - FirstEnergy recorded a net charge to income during the year ended December 31, 2002 of $57.1 million (net of income taxes of $13.6 million) relative to decisions to retain interests in the Avon and Emdersa businesses previously classified as held for sale - see Note 3. This net charge represents the aggregate results of operations of Avon and Emdersa for the respective periods these businesses were held for sale. This charge was previously reported on the Consolidated Statement of Income as cumulative effect of a change in accounting. In April 2003 it was determined that charge should instead have been classified in operations. As further, discussed in Note 3, the decision to retain Avon and Emdersa were made in the first and fourth quarters, respectively, of the year ended 2002. The results of operations for these businesses for the quarters in which the decisions were made to retain them have been classified in their respective revenue and expense captions on the Consolidated Statement of Income for the year ended December 31, 2002. The aggregate results of operations for periods preceding the periods in which the decision was made to retain Emdersa has been recorded net on the Consolidated Statement of Income as a "Cumulative Adjustment for Retained Businesses Previously Held for Sale. This change in classification had no effect on previously reported net income. The effects of this change on the Consolidated Statement of Income previously reported for the year ended December 31, 2002 are as follows:
AS PREVIOUSLY REVISED PRESENTED PRESENTATION* ------------- ------------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues $ 12,151,997 $ 12,247,401 Expenses 9,969,814 9,995,740 Cumulative adjustment for retained businesses previously held for sale -- (93,723) ------------- ------------- Income before interest and income taxes 2,182,183 2,157,938 Net interest charges 946,306 965,582 Income taxes 549,476 563,076 Income before cumulative effect of accounting change 686,401 629,280 Cumulative effect of accounting change (57,121) -- ------------- ------------- Net income $ 629,280 $ 629,280 ------------- ------------- Basic Earnings Per Share: Income before cumulative effect of accounting change $ 2.34 $ 2.15 Cumulative effect of accounting change (0.19) -- ------------- ------------- Net income $ 2.15 $ 2.15 ============= ============= Diluted Earnings Per Share: Income before cumulative effect of accounting change $ 2.33 $ 2.14 Cumulative effect of accounting change (0.19) -- ------------- ------------- Net income $ 2.14 $ 2.14 ============= =============
* Revised as discussed above and filed on Form 10-K/A Amendment No. 1. Excludes effect of restatements discussed in note 1(M) below. (M) RESTATEMENTS The Company is restating its financial statements for the year ended December 31, 2002. The primary modifications include revisions to reflect a change in the method of amortizing costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. In addition, certain other immaterial adjustments related to the recognition of a valuation allowance on a tax benefit recognized in 2002 and other adjustments are now reflected in results for the year ended December 31, 2002. 55 Transition Cost Amortization - As discussed above under Regulatory Matters in Note 2(D), FirstEnergy, OE, CEI and TE amortize transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements, but not in the financial statements prepared under GAAP. The Ohio companies have revised the amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period compared with the method previously applied. The change in method results in no change in total amortization of the previously recorded regulatory assets recovered under the transition plan through the end of 2009. Above-Market Lease Costs In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior. The merger was accounted for as an acquisition of Centerior, the parent company of CEI and TE, under the purchase accounting rules of APB 16. In connection with the reassessment of the accounting for the Transition Plan, the Company reassessed its accounting for the Centerior purchase and determined that above-market lease liabilities should have been recorded at the time of the merger. Accordingly, as of 2002, the Company recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE recorded an increase in goodwill related to the above market lease costs for Beaver Valley Unit 2 because regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional liability would have increased goodwill at the date of the merger. The corresponding impact of the above-market lease liability for the Bruce Mansfield Plant was recorded as a regulatory asset since regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided under the Company's regulatory plan in effect at the time of the merger and subsequently under the transition plan. The total above-market lease obligation of $722 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017 (approximately $37 million per year). The additional goodwill has been recorded on a net basis, reflecting amortization that would have been recorded through 2001, when goodwill amortization ceased with the adoption of SFAS 142. The total above market lease obligation of $755 million associated with the Bruce Mansfield Plant is being amortized through the end of 2016 (approximately $48 million per year). Before the start of the Transition Plan in fiscal 2001, the regulatory asset would have been amortized at the same rate as the lease obligation. Beginning in 2001, the remaining unamortized regulatory asset would have been included in CEI's and TE's amortization schedules for regulatory assets and amortized through the end of the recovery period - 2009 for CEI and 2007 for TE. FirstEnergy has reflected the net impact of the accounting for these items for the period from the merger in 1997 through 2001 in the 2002 financial statements. The cumulative impact to net income recorded in 2002 related to these prior periods increased net income by $5.9 million in the restated 2002 financial statements and is reflected as a reduction in other operating expenses in the accompanying consolidated statement of income. In addition, the impact increased the following balances in the consolidated balance sheet as of January 1, 2002:
INCREASE (DECREASE) (IN THOUSANDS) Goodwill............................ $ 381,780 Regulatory assets................... 636,100 ----------- Total assets........................ $1,017,880 ========== Other current liabilities........... 84,600 Deferred income taxes............... (262,580) Deferred investment tax credits..... (828) Other deferred credits.............. 1,190,800 ----------- Total liabilities................... $1,011,992 ==========
The adjustments were not reflected in the periods prior to the year ended December 31, 2002 as the impact was not material. 56 The after-tax effect of the actual 2002 impact of these items decreased net income for the year ended December 31, 2002, by $71 million, or $0.24 per share. The adjustments described above are anticipated to result in a decrease in reported net income through 2005 and an increase in net income for the period 2006 through 2017, the end of the lease term for Beaver Valley Unit 2. After giving effect to the restatement, total transition cost amortization (including above market leases) is expected to approximate the following for the years from 2003 through 2009 (in millions). 2003 $685 2004 786 2005 913 2006 378 2007 213 2008 163 2009 44
DISCONTINUED OPERATIONS - On April 18, 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. As a result of the abandonment, FirstEnergy recorded a $67.4 million change in the second quarter 2003. As a result of FirstEnergy's divestiture of its ownership in Emdersa in April 2003, FirstEnergy has reflected the results of this business during 2002 as a discontinued operation in the restated year ended December 31, 2002 Consolidated Statement of Income as "Discontinued Operations". There was no impact on the year ended December 31, 2001 Consolidated Statement of Income as Emdersa was reported as an asset held for sale during this period. The following table summarizes Emdersa's major assets and liabilities included in FirstEnergy's Consolidated Balance Sheet as of December 31, 2002. The amounts have not been reflected separately in the accompanying balance sheets as the amounts are not significant to the Consolidated Balance Sheet. (in thousands) -------------- Assets Abandoned: Current assets $ 17,344 Property, plant and equipment 61,980 Other 8,737 -------- Total Assets $ 88,061 ======== Liabilities Related to Assets Abandoned: Current liabilities $ 12,777 Long-term debt 100,202 Other 10,548 -------- Total Liabilities $123,527 ========
OTHER ADJUSTMENTS - 57 The Company has included in this restatement certain immaterial adjustments that were not previously recognized in 2002 related to the recognition of a valuation allowance on a tax benefit recognized in 2002 and other adjustments. The impact of these adjustments decreased net income by $11.3 million The effects of all of these adjustments on the Consolidated Statement of Income, Consolidated Balance Sheet and Consolidated Statement of Cash Flows previously reported, and revised per Note 3(L) above, for December 31, 2002 are as follows:
TRANSITION ABOVE AS PREVIOUSLY COST MARKET DISCONTINUED AS REPORTED AMORTIZATION LEASES OPERATIONS OTHER RESTATED -------- ------------ ------ ---------- ----- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) CONSOLIDATED STATEMENT OF INCOME REVENUES: Electric utilities $ 9,165,805 $ -- $ -- $ -- $ -- $ 9,165,805 Unregulated businesses 3,081,596 -- -- (16,875) -- 3,064,721 ------------ ------------ ------------ ------------ ------------ ------------ Total revenues 12,247,401 -- -- (16,875) -- 12,230,526 ------------ ------------ ------------ ------------ ------------ ------------- EXPENSES: Fuel and purchased power 3,673,610 -- -- -- (10,700) 3,662,910 Purchased gas 592,116 -- -- -- -- 592,116 Other operating expenses 3,973,781 -- (90,688) (8,984) 14,800 3,888,909 Provision for depreciation and amortization 1,105,904 150,474 50,272 (807) -- 1,305,843 General taxes 650,329 -- -- -- -- 650,329 ------------ ------------ ------------ ------------ ------------ ------------- Total expenses 9,995,740 150,474 (40,416) (9,791) 4,100 10,100,107 ------------ ------------ ------------ ------------ ------------ ------------- CUMULATIVE ADJUSTMENT FOR RETAINED BUSINESSES PREVIOUSLY HELD FOR SALE (NOTE 2L) (93,723) -- -- 93,723 -- -- ------------ ------------ ------------ ------------ ------------ ------------- INCOME BEFORE INTEREST AND INCOME TAXES 2,157,938 (150,474) 40,416 86,639 (4,100) 2,130,419 ------------ ------------ ------------ ------------ ------------ ------------ NET INTEREST CHARGES: Interest expense 911,109 -- -- (837) -- 910,272 Capitalized interest (24,474) -- -- -- -- (24,474) Subsidiaries' preferred stock dividends 78,947 -- -- -- (3,300) 75,647 ------------ ------------ ------------ ------------ ------------ ------------- Net interest charges 965,582 -- -- (837) (3,300) 961,445 ------------ ------------ ------------ ------------ ------------ ------------- INCOME TAXES 563,076 (30,920) (13,962) -- 10,500 528,694 ------------ ------------ ------------ ------------ ------------ ------------ INCOME BEFORE DISCONTINUED OPERATIONS 629,280 (119,554) 54,378 87,476 (11,300) 640,280 DISCONTINUED OPERATIONS -- -- -- (87,476) -- (87,476) ------------ ------------ ------------ ------------ ------------ ------------- NET INCOME $ 629,280 $ (119,554) $ 54,378 -- $ (11,300) $ 552,804 ============ ============ ============ ============ ============ ============ BASIC EARNINGS PER SHARE OF COMMON STOCK $ 2.15 $ (0.41) $ 0.19 -- $(0.04) $ 1.89 DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 2.14 $ (0.41) $ 0.19 -- $(0.04) $ 1.88
58
TRANSITION ABOVE AS PREVIOUSLY COST MARKET AS REPORTED AMORTIZATION LEASES OTHER RESTATED -------- ------------ ----------- ----- -------- (IN THOUSANDS) CONSOLIDATED BALANCE SHEET ASSETS CURRENT ASSETS: Cash and cash equivalents $ 196,301 $ -- $ -- $ -- $ 196,301 Receivables - Customers 1,153,486 -- -- -- 1,153,486 Other 473,106 -- -- (3,500) 469,606 Materials and supplies, at average cost Owned 253,047 -- -- -- 253,047 Under consignment 174,028 -- -- -- 174,028 Prepayments and other 203,630 -- -- -- 203,630 ------------ ------------ ------------ ------------ ------------ 2,453,598 -- -- (3,500) 2,450,098 ------------ ------------ ------------ ------------ ------------ PROPERTY, PLANT AND EQUIPMENT: In service 20,372,224 -- -- -- 20,372,224 Less--Accumulated provision for depreciation 8,551,427 -- -- 1,500 8,552,927 ------------ ------------ ------------ ------------ ------------ 11,820,797 -- -- (1,500) 11,819,297 Construction work in progress 859,016 -- -- 859,016 ------------ ------------ ------------ ------------ ------------ 12,679,813 -- -- (1,500) 12,678,313 ------------ ------------ ------------ ------------ ------------ INVESTMENTS: Capital trust investments (Note 4) 1,079,435 -- -- -- 1,079,435 Nuclear plant decommissioning trusts 1,049,560 -- -- -- 1,049,560 Letter of credit collateralization (Note 4) 277,763 -- -- -- 277,763 Other 918,874 -- -- -- 918,874 ------------ ------------ ------------ ------------ ------------ 3,325,632 -- 3,325,632 ------------ ------------ ------------ ------------ ------------ DEFERRED CHARGES: Regulatory assets 8,323,001 (154,600) 585,000 -- 8,753,401 Goodwill 5,896,292 -- 381,780 -- 6,278,072 Other (Note 2I) 902,437 -- -- (1,600) 900,837 ------------ ------------ ------------ ------------ ------------ 15,121,730 -- -- (1,600) 15,932,310 ------------ ------------ ------------ ------------ ------------ $ 33,580,773 $ (154,600) $ 466,780 $ (6,600) $ 34,386,353 ============ ============ ============ ============ ============ LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt and preferred stock $ 1,702,822 $ -- $ -- $ -- $ 1,702,822 Short-term borrowings (Note 6) 1,092,817 -- -- -- 1,092,817 Accounts payable 918,268 -- -- (11,800) 906,468 Accrued taxes 456,178 -- -- (1,057) 455,121 Other 1,000,415 -- 84,600 8,800 1,093,815 ------------ ------------ ------------ ------------ ------------ 5,170,500 -- 84,600 (4,057) 5,251,043 ------------ ------------ ------------ ------------ ------------ CAPITALIZATION Common stockholders' equity(a) 7,120,049 (123,680) 58,504 (4,212) 7,050,661 Preferred stock of consolidated subsidiaries -- Not subject to mandatory redemption 335,123 -- -- -- 335,123 Subject to mandatory redemption 18,521 -- -- -- 18,521 Subsidiary-obligated mandatorily redeemable preferred securities (Note 5F) 409,867 -- -- -- 409,867 Long-term debt 10,872,216 -- -- -- 10,872,216 ------------ ------------ ------------ ------------ ------------ 18,755,776 (123,680) 58,504 (4,212) 18,686,388 ------------ ------------ ------------ ------------ ------------ DEFERRED CREDITS: Accumulated deferred income taxes 2,367,997 (31,346) (282,324) 15,355 2,069,682 Accumulated deferred investment tax credits 235,758 426 -- -- 236,184 Nuclear plant decommissioning costs 1,254,344 -- -- (10,786) 1,243,558 Power purchase contract loss liability 3,136,538 -- -- -- 3,136,538 Retirement benefits 1,564,930 -- -- -- 1,564,930 Other 1,094,930 -- 1,106,000 (2,900) 2,198,030 ------------ ------------ ------------ ------------ ------------ 9,654,497 (30,920) 823,676 1,669 10,448,922 ------------ ------------ ------------ ------------ ------------ COMMITMENTS, GUARANTEES AND CONTINGENCIES $ 33,580,773 $ (154,600) $ 966,780 $ (6,600) $ 34,386,353 ============ ============ ============ ============ ============
(a) Other adjustments include an impact to other comprehensive income. 60
TRANSITION AS PREVIOUSLY COST LEASE DISCONTINUED AS REPORTED AMORTIZATION OBLIGATIONS OPERATIONS OTHER RESTATED ----------- ----------- ----------- ----------- ----------- ----------- (IN THOUSANDS) CONSOLIDATED STATEMENT OF CASH FLOWS CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 629,280 $ (119,554) $ 54,378 $ -- $ (11,300) $ 552,804 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 1,105,904 150,474 50,272 (807) -- 1,305,843 Nuclear fuel and lease amortization 80,507 -- -- -- -- 80,507 Other amortization, net (Note 2) (16,593) -- -- -- -- (16,593) Deferred costs recoverable as regulatory assets (362,956) -- -- -- -- (362,956) Avon investment impairment (Note 3) 50,000 -- -- -- -- 50,000 Deferred income taxes, net 89,860 (29,666) (13,962) -- 10,500 56,732 Investment tax credits, net (27,071) (1,254) -- -- -- (28,325) Cumulative adjustment (see Note 2 (L)) 93,723 -- -- (93,723) -- -- Discontinued operations (see Note (M)) -- -- -- 87,476 -- 87,476 Receivables (85,307) -- -- -- -- (85,307) Materials and supplies (29,557) -- -- -- -- (29,557) Accounts payable 220,762 -- -- -- -- 220,762 Deferred lease costs -- -- (84,800) -- -- (84,800) Other (Note 9) 166,735 -- (5,888) 7,054 800 168,701 ----------- ----------- ----------- ----------- ----------- ----------- Net cash provided from operating activities 1,915,287 -- -- -- -- 1,915,287 ----------- ----------- ----------- ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Net cash provided from (used for) financing activities (1,123,469) -- -- -- -- (1,123,469) ----------- ----------- ----------- ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Net cash provided from (used for) investing activities (815,695) -- -- -- -- (815,695) ----------- ----------- ----------- ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents (23,877) -- -- -- -- (23,877) Cash and cash equivalents at beginning of year 220,178 -- -- -- -- 220,178 ----------- ----------- ----------- ----------- ----------- ----------- Cash and cash equivalents at end of year $ 196,301 $ -- $ -- -- $ -- $ 196,301 =========== =========== =========== =========== =========== ===========
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 an ownership voting interest. Originally, in accordance with applicable accounting guidance, the earnings of those foreign operations were not recognized in current earnings from the date of the GPU acquisition. However, as a result of the decision to retain an ownership interest in Avon in the quarter ended March 31, 2002, EITF Issue No. 90-6, "Accounting for Certain Events Not Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be Sold" required FirstEnergy to reallocate the purchase price of GPU based on amounts as of the purchase date as if Avon had never been held for sale, including reversal of the effects of having applied EITF Issue No. 87-11, to the transaction. The effect of reallocating the purchase price and reversal of the effects of Issue No. 87-11, including the allocation of capitalized interest, has been reflected in the Consolidated Statement of Income for the year ended 61 December 31, 2002 by reclassifying certain revenue and expense amounts related to activity during the quarter ended March 31, 2002 to their respective income statement classifications. See Note 2(L) for the effects of the change in classification. In the fourth quarter of 2002, FirstEnergy recorded a $50 million charge 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. Additionally, under EITF Issue No. 90-6, FirstEnergy recorded in the fourth quarter of 2002 a one-time, non-cash charge included as a "Cumulative Adjustment for Retained Businesses Previously Held for Sale" on its 2002 Consolidated Statement of Income related to Emdersa's cumulative results of operations from November 7, 2001 through September 30, 2002. The amount of this one-time, after-tax charge was $93.7 million, or $0.32 per share of common stock (comprised of $108.9 million in currency transaction losses arising principally from U.S. dollar denominated debt, offset by $15.2 million of operating income). See Note 2(L) for the effects of the change in classification and Note 2(M) for discontinued operations treatment. On October 1, 2002, FirstEnergy began consolidating the results of Emdersa's operations in its financial statements. In addition to the currency transaction losses of $108.9 million, FirstEnergy recognized a currency translation adjustment 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. 62 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. 64 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. 65 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: 66
(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 $4.3 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. 67 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. 68 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 69 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. 70 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: 71 SEGMENT FINANCIAL INFORMATION
REGULATED COMPETITIVE RECONCILING SERVICES SERVICES OTHER(C) ADJUSTMENTS CONSOLIDATED (C) -------- -------- -------- ----------- ---------------- (IN MILLIONS) 2002 External revenues $ 8,794 $3,015 $409 $ 13 (a) $ 12,231 Internal revenues 1,052 1,666 478 (3,196) (b) -- Total revenues 9,846 4,681 887 (3,183) 12,231 Depreciation and amortization 1,235 30 41 -- 1,306 Net interest charges 587 46 386 (58) (b) 961 Income taxes 698 (87) (82) -- 529 Income before discontinued operations 938 (119) (179) -- 640 Discontinued operations -- -- (87) -- (87) Net income 927 (108) (266) -- 553 Total assets 30,494 2,281 1,611 -- 34,386 Total goodwill 5,993 285 -- -- 6,278 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. (c) Restated - See Notes 2L and 2M. 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 $33,628 $7,991 $32,187 Foreign countries* 339 758 8 5,165 ---------- ---------- ---------- -------- Total $12,247 $34,386 $7,999 $37,352 ========== ========== ========== ========
* See Note 3 for discussion of future divestitures of international operations and Note 2L for discussion of revised financial data. 72 9. OTHER INFORMATION: The following financial data provides supplemental unaudited information to the consolidated financial statements and notes previously reported in 2001 and 2000: (A) CONSOLIDATED STATEMENTS OF CASH FLOWS
2002 2001 2000 ---- ---- ---- RESTATED (IN THOUSANDS) Other Cash Flows From Operating Activities: Accrued taxes $ 36,566 $ 8,915 $ (84) Accrued interest (26,281) 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 68,452 (97,882) 76,441 --------- --------- --------- Total-Other $ 168,701 $(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 ---- ---- ---- RESTATED (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 $(397,506) $(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. 73 (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 after June 15, 2003 (FirstEnergy's 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. 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 FirstEnergy 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 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 $11.6 million. 74 11. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
THREE MONTHS ENDED MARCH 31, 2002 (C)(D) JUNE 30, 2002 (D) SEPTEMBER 30, 2002 (D) DECEMBER 31, 2002 ------------------------------------------------------------------------------------------------------------------------- AS AS AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED --------- --------- --------- --------- --------- --------- --------- --------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues (a) $ 2,853.3 $ 2,853.3 $ 2,898.5 $ 2,898.5 $ 3,451.2 $ 3,451.2 $ 3,044.4 $ 3,027.5 Expenses (a) 2,363.6 2,362.3 2,230.4 2,272.7 2,681.7 2,724.0 2,746.8 2,741.1 Cumulative adjustment -- -- -- -- -- -- (93.7) -- --------- --------- --------- --------- --------- --------- --------- --------- Income Before Interest and Income Taxes 489.7 491 668.1 625.8 769.5 727.2 203.9 286.4 Net Interest Charges 278.7 278.7 250.3 250.3 220.4 220.4 216.2 212.0 Income Taxes 94.4 93.9 184.6 167.7 238.9 221.9 34.6 45.1 --------- --------- --------- --------- --------- --------- --------- --------- Income Before Discontinued Operations 116.6 118.4 233.2 207.8 310.3 284.8 (46.9) 29.3 Discontinued Operations -- -- -- -- -- -- -- (87.5) --------- --------- --------- --------- --------- --------- --------- --------- Net Income (Loss) $ 116.6 $ 118.4 $ 233.2 $ 207.8 $ 310.3 $ 284.8 $ (46.9) $ 58.2 ========= ========= ========= ========= ========= ========= ========= ========= Basic Earnings (Loss) Per Share of Common Stock $ .36 $ 0.41 $ .74 $ 0.71 $ .99 $ 0.97 $ (.16) $ (.20) Diluted Earnings (Loss) Per Share of Common Stock $ .36 $ 0.40 $ .73 $ 0.71 $ .98 $ 0.97 $ (.16) $ (.20) ========= ========= ========= ========= ========= ========= ========= =========
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. (c) See Note 2L for discussion of revised financial data. (d) See Note 2(M) for discussion of Restated financial data. Related to impact of transition plan amortization and above works leases. (e) Includes the impact of above makes totaling $11.3 million, principally related to the recognition of a valuation allowance on a tax benefit previously recognized in the fourth quarter of 2002. 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 75 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 ------- -------
76 13. SUBSEQUENT EVENTS (UNAUDITED) ENVIRONMENTAL MATTERS- On August 8, 2003, FirstEnergy, OE and Penn reported a development regarding a complaint filed by the U.S. Department of Justice with respect to the W.H. Sammis Plant (see Note 7(D) Commitments, Guarantees and Contingencies - Environmental Matters). As reported, on August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning March 15, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, may have a material adverse impact on the Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter. REGULATORY MATTERS- New Jersey On July 25, 2003, FirstEnergy and JCP&L announced that review is underway concerning a decision by the NJBPU on JCP&L's rate proceeding (See Note 2(D)). Based on that review, JCP&L will decide its appropriate course of action, which could include filing a request for reconsideration with the NJBPU and possibly an appeal to the Appellate Division of the Superior Court of New Jersey. In its ruling, the NJBPU reduced JCP&L's annual revenues by approximately $62 million, for an average rate decrease of 3 percent, effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5 percent on JCP&L's rate base for the next 6 to 12 months. During that period, JCP&L would initiate another proceeding to request recovery of additional expenses incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75 percent or decrease it to 9.25 percent, depending on its assessment of the reliability of JCP&L's service. Any reduction could be retroactive to August 1, 2003. The NJBPU decision reflects elimination of $111 million in annual customer credits mandated by the New Jersey Electric Discount and Energy Competition Act (EDECA); a $223 million reduction in the energy delivery charge; a net $1 million increase in the SBC; and a $49 million increase in the MTC. The $1 million net SBC increase reflects approximately a $22 million increase related to universal services' costs previously approved in a separate proceeding, as well as reductions in other components of the SBC. The MTC would allow for the recovery of $465 million of deferred energy costs over the next 10 years on an interim basis, thus disallowing $153 million of the $618 million provided for in the settlement agreement. This decision reflects the NJBPU's belief that a hindsight review comparing JCP&L's power purchases to spot market prices provides the appropriate benchmark for recovery. JCP&L's deferred energy costs primarily reflect mandated purchase power contracts with NUG's that are above wholesale market prices, and costs of providing basic generation service to customers in excess of the company's capped basic generation service charges during the transition period under EDECA, which ends August 1, 2003. At that time, the generation portion of most customer bills will increase by an average of 7.5 percent as a result of the outcome of the basic generation service auction conducted earlier this year by the BPU. In the second quarter of 2003, JCP&L recorded charges to net income aggregating $158 million ($94 million net of tax) consisting of the $153 million deferred energy costs and other regulatory assets. On July 25, 2003, the NJBPU approved a Stipulation of Settlement between the parties and authorized the recovery of the total $135 million of the Freehold buyout costs, eliminating the interim nature of the recovery. Pennsylvania On April 2, 2003, the PPUC remanded the merger savings issue to the Office of Administrative Judge ("ALJ") and directed Met-Ed and Penelec submit a position paper by May 2, 2003 on the status of the Settlement Stipulation in light of the Commonwealth Court's decision ("Court Order"). In summary, the Met-Ed and Penelec submitted to the PPUC the following position: - On January 16, 2003, the Pennsylvania Supreme Court denied or quashed all appeals arising from the Court Order, thus rendering the Court Order final. 77 - Because the parties sought to stay the PPUC's June 20, 2001 order in which the Settlement Stipulation was approved, all terms and conditions included therein that were not inconsistent with the Court Order remained in effect. - Only those provisions related to POLR cost recovery and POLR deferral, issues addressed by the PPUC and expressly rejected by the Commonwealth Court, must be removed from the Settlement Stipulation. - The GENCO Code of Conduct must be reinstated consistent with the Court Order. - All other provisions included in the Stipulation unrelated to these three issues remain in effect. On or about June 2, 2003, parties filed comments in response to the position presented by Met-Ed and Penelec. The other parties' responses included significant disagreement with the position paper and disagreement among the other parties themselves, including the Stipulation's original signatory parties. Some parties believe that no portion of the Stipulation has survived the Commonwealth Court's Order. Based upon these comments, it became clear that many of the parties not only disagreed with Met-Ed and Penelec, but also disagreed among themselves. Partially because of this lack of consensus among the parties, Met-Ed and Penelec submitted a letter on June 11, 2003, to the ALJ informing the ALJ and all other parties that Met-Ed and Penelec were voiding the Settlement Stipulation, pursuant to the termination provisions found therein. Notwithstanding the voiding of the Settlement Stipulation, Met-Ed and Penelec voluntarily agreed to retain virtually all of the customer benefits provided by the Settlement Stipulation, including, among others, funding for renewable energy resource and demand response programs. Met-Ed and Penelec also agreed to cap distribution rates at current levels through 2007, provided that the PPUC finds during the remanded merger saving proceedings that Met-Ed and Penelec have satisfied the public interest test applicable to mergers and leave the quantification of merger savings for a subsequent rate proceedings. They believe this will significantly simplify the issues in the pending action by reinstating Met-Ed's and Penelec's Restructuring Settlement previously approved by the PPUC. In addition, they have agreed to voluntarily continue certain Stipulation provisions including funding for energy and demand side response programs and to cap distribution rates at current levels through 2007. This voluntary distribution rate cap is contingent upon a finding that Met-Ed and Penelec have satisfied the "public interest" test applicable to mergers and that any rate impacts of merger savings will be dealt with in a subsequent rate case. Met-Ed and Penelec believe that their actions in voiding the Settlement Stipulation will simplify the issues and limit them to the treatment of merger savings and whether Met-Ed's and Penelec's accounting is consistent with the Court Order. INTERNATIONAL OPERATIONS- Pending Sale of Remaining Investment in Avon and Sale of Note from Aquila On May 22, 2003, FirstEnergy announced it reached an agreement to sell its 20.1 percent interest in Avon to Scottish and Southern Energy plc; that agreement also includes Aquila's 79.9 percent interest (See Note 3). Under terms of the agreement, Scottish and Southern will pay FirstEnergy and Aquila an aggregate $70 million (FirstEnergy's share would be approximately $14 million). Avon's debt will remain with that company. FirstEnergy also recognized in the second quarter of 2003 an impairment of $12.6 million ($8.2 million after tax) related to the carrying value of the note receivable from from the initial sale of a 79.9 percent interest in Avon that occurred in May 2002. After receiving the first annual installment payment of $19 million in May 2003, FirstEnergy sold the remaining balance of the note in the secondary market and received $63.2 million in proceeds on July 28, 2003. Emdersa On April 18, 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. As a result of the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67.4 million, or $0.23 per share of common stock in the second quarter of 2003. This charge is the result of realizing the CTA losses through current period earnings ($89.8 million, or $0.30 per share), partially offset by the gain recognized from abandoning FirstEnergy's investment in Emdersa ($22.4 million, or $0.07 per share). Since FirstEnergy had previously recorded $90 million of CTA adjustments in OCI, the net effect of the $67.4 million charge was an increase in common stockholders' equity of $22.4 million. The $67.4 million charge does not include the anticipated income tax benefits related to the abandonment, which were fully reserved during the second quarter. FirstEnergy anticipates tax benefits of approximately $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million of tax benefits would reduce goodwill recognized in connection with the acquisition of GPU. 78 OTHER MATTERS- It is FirstEnergy's understanding that, as of August 18, 2003, five individual described herein shareholder-plaintiffs have filed separate complaints against FirstEnergy Corp. alleging various securities law violations in connection with the restatement of earnings period. Most of these complaints have not yet been officially served on the Company. Moreover, FirstEnergy is still reviewing the suits that have been served in preparation for a responsive pleading. FirstEnergy is , however, aware that in each case, the plaintiffs are seeking certification from the court to represent a class of similarly situated shareholders. On August 14, 2003, eight states and southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. The cause of the outage has not been determined. Having restored service to its customers, FirstEnergy is now in the process of accumulating data and evaluating the status of its electrical system prior to and during the outage event and would expect that the same effort Is under way at utilities and regional transmission operators across the region. As of August 18, 2003, the following facts about FirstEnergy's system were known. Early in the afternoon of August 14, hours before the event, Unit 5 of the Eastlake Plant in Eastlake, Ohio tripped off. Later in the afternoon, three FirstEnergy transmission lines and one owned by American Electric Power and FirstEnergy tripped out of service. The Midwest Independent System Operator (MISO), which oversees the regional transmission grid, indicated that there were a number of other transmission line trips in the region outside of FirstEnergy's system. FirstEnergy customers experienced no service interruptions resulting from these conditions. Indications to FirstEnergy were that Company's system was stable. Therefore, no isolation of FirstEnergy's system was called for. In addition, FirstEnergy determined that its computerized system for monitoring and controlling its transmission and generation system was operating, but the alarm screen function was not. However, MISO's monitoring system was operating properly. It is clear that extensive data needs to be gathered and analyzed in order to determine with any degree of certainty the circumstances that led to the outage. This is a very complex situation, far broader than the power line outages FirstEnergy experienced on its system. From the preliminary data that has been gathered., it is clear that the transmission grid in the Eastern Interconnection, not just within FirstEnergy's system, was experiencing unusual electrical conditions at various times prior to the event. These included unusual voltage and frequency fluctuations and load swings on the grid. FirstEnergy is committed to working with the North American Electric Reliability Council and others involved to determine exactly what events in the entire affected region led to the outage. There is no timetable as to when this entire process will be completed. It is, however, expected to last several weeks, at a minimum. RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED- SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and is effective at the beginning of the first interim period beginning after June 15, 2003 (FirstEnergy's third quarter of 2003) for all other financial instruments. FirstEnergy did not enter into or modify any financial instruments within the scope of SFAS 150 during June 2003. Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy expects to classify as debt the preferred stock of consolidated subsidiaries subject to mandatory redemptions with a carrying value of approximately $19 million as of June 30, 2003. Subsidiary preferred dividends on FirstEnergy's Consolidated Statements of Income are currently included in net interest charges. Therefore, the application of SFAS 150 will not require the reclassification of such preferred dividends to net interest charges. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence in a contract of a general index, such as the Consumer Price Index, would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. FirstEnergy is currently assessing the new guidance and has not yet determined the impact on its financial statements. 79 EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus will be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. FirstEnergy is currently assessing the new EITF consensus and has not yet determined the impact on its financial position or results of operations following adoption. 80 EX-23 5 l02705aexv23.txt EXHIBIT 23 EXHIBIT 23 FIRSTENERGY CORP. CONSENT OF INDEPENDENT AUDITORS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-48587, 333-102074 and 333-103865) 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, except as to Note 2(L), which is as of May 9, 2003, and Notes 2(M) and 8, which are as of August 18, 2003, relating to the consolidated financial statements, which appears in the restated Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K/A. PricewaterhouseCoopers LLP Cleveland, Ohio August 18, 2003 57 EX-31.1 6 l02705aexv31w1.txt EXHIBIT 31.1 EXHIBIT 31.1 CERTIFICATION I, H. Peter Burg, certify that: 1. I have reviewed this amended annual report on Form 10-K/A of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison 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 each registrant as of, and for, the periods presented in this annual report; 4. Each 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 such registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to such 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 such 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. Each registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to such registrant's auditors and the audit committee of such 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 such registrant's ability to record, process, summarize and report financial data and have identified for such 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 such registrant's internal controls; and 6. Each 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: August 18, 2003 /s/H. Peter Burg --------------------------------------- H. Peter Burg Chief Executive Officer 59 EX-31.2 7 l02705aexv31w2.txt EXHIBIT 31.2 EXHIBIT 31.2 CERTIFICATION I, Richard H. Marsh, certify that: 1. I have reviewed this amended annual report on Form 10-K/A of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison 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 each registrant as of, and for, the periods presented in this annual report; 4. Each 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 such registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to such 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 such 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. Each registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to such registrant's auditors and the audit committee of such 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 such registrant's ability to record, process, summarize and report financial data and have identified for such 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 such registrant's internal controls; and 6. Each 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: August 18, 2003 /s/Richard H. Marsh ------------------------------------- Richard H. Marsh Chief Financial Officer 60 EX-32 8 l02705aexv32.txt EXHIBIT 32 EXHIBIT 32 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 FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company on Form 10-K/A, as amended, for the year ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of each of the Companies does hereby certify, pursuant to 18 U.S.C. Section 1350, as adoPTEd pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge: (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/H. Peter Burg ---------------------------------- H. Peter Burg Chief Executive Officer August 18, 2003 /s/Richard H. Marsh ---------------------------------- Richard H. Marsh Chief Financial Officer August 18, 2003 61 EX-12.2 9 l02705aexv12w2.txt EXHIBIT 12.2 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) RESTATED EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items ........................ $301,320 $297,689 $336,456 $350,212 $356,159 Interest and other charges, before reduction for amounts capitalized .................................... 235,317 225,358 211,364 187,890 144,170 Provision for income taxes ............................... 191,261 191,835 212,580 239,135 255,915 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 $858,713 ======== ======== ======== ======== ======== 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 3.44 ======== ======== ======== ======== ========
- ---------- (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. 51 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) RESTATED EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items ................................... $301,320 $297,689 $336,456 $350,212 $356,159 Interest and other charges, before reduction for amounts capitalized 235,317 225,358 211,364 187,890 144,170 Provision for income taxes .......................................... 191,261 191,835 212,580 239,135 255,915 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 $858,713 ======== ======== ======== ======== ======== 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 3.30 ======== ======== ======== ======== ========
- ---------- (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. 52 EX-13.1 10 l02705aexv13w1.txt EXHIBIT 13.1 Exhibit 13.1 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.................................... 2-13 Consolidated Statements of Income....................................... 14 Consolidated Balance Sheets............................................. 15 Consolidated Statements of Capitalization............................... 16-17 Consolidated Statements of Common Stockholder's Equity.................. 18 Consolidated Statements of Preferred Stock.............................. 18 Consolidated Statements of Cash Flows................................... 19 Consolidated Statements of Taxes........................................ 20 Notes to Consolidated Financial Statements.............................. 21-36 Report of Independent Auditors.......................................... 37 Report of Independent Public Auditors................................... 38
OHIO EDISON COMPANY SELECTED FINANCIAL DATA
2002 2001 2000 1999 1998 - -------------------------------------------------------------------------------------------------------------------- RESTATED (SEE NOTE 1(M)) (IN THOUSANDS) Operating Revenues................................ $2,948,675 $3,056,464 $2,726,708 $2,686,949 $2,519,662 --------------------------------------------------------------- Operating Income.................................. $ 453,831 $ 466,819 $ 482,321 $ 473,042 $ 486,920 --------------------------------------------------------------- Income Before Extraordinary Item.................. $ 356,159 $ 350,212 $ 336,456 $ 297,689 $ 301,320 --------------------------------------------------------------- Net Income........................................ $ 356,159 $ 350,212 $ 336,456 $ 297,689 $ 270,798 --------------------------------------------------------------- Earnings on Common Stock.......................... $ 349,649 $ 339,510 $ 325,332 $ 286,142 $ 258,828 --------------------------------------------------------------- Total Assets...................................... $7,790,041 $7,915,953 $8,154,151 $8,700,746 $8,923,826 --------------------------------------------------------------- CAPITALIZATION AT DECEMBER 31: Common Stockholder's Equity.................... $2,839,255 $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......................... $4,172,172 $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
1 OHIO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate", "potential", "expect", "believe", "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), availability and cost of capital, inability of the Davis-Besse Nuclear Power Station to restart (including because of an inability to obtain a favorable final determination from the Nuclear Regulatory Commission) in the fall of 2003, inability to accomplish or realize anticipated benefits from strategic goals and other similar factors. 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. RESTATED FINANCIAL STATEMENTS FOR CHANGE IN METHOD OF AMORTIZING OHIO TRANSITION COSTS OE has restated its financial statements for the year ended December 31, 2002, to reflect a change in the method of amortizing the costs associated with the Ohio transition plan. OE amortizes transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in 2 applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred and are not reflected as regulatory assets in the financial statements prepared under generally accepted accounting principles (GAAP). OE has revised the amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period compared with the method previously applied. The change in method results in no change in total amortization of the regulatory assets that are recovered from January 1, 2001, through the transition period which is expected to end in 2006. After giving effect to the restatement, total transition cost amortization (including above market leases) is expected to approximate the following for the years from 2003 through 2006 (in millions). 2003.............. $389 2004.............. 456 2005.............. 553 2006.............. 178 The revised amortization method is expected to decrease pre-tax income by $13 million in 2003 and $10 million in 2004. It should increase pretax income that would have been reported using the previous method by $8 million in 2005 and $22.3 million in 2006. The change in amortization resulted in a decrease in net income of $5.4 million and included an increase in net income of $15.4 million from the cumulative impact of the adjustments related to 2001 and a $20.8 million decrease in net income for additional amortization expense in 2002. The net adjustment is reflected as an increase of $14.7 million in depreciation and amortization expense and a decrease of $9.3 million in income tax expense in the accompanying consolidated statement of income as restated. The Company has also included in this restatement certain immaterial adjustments that were not previously recognized in 2002. The impact of these adjustments reduced net income reported for 2002 by $1.9 million. See Note 1(M) to the consolidated financial statements. The effects of the changes on the Consolidated Statement of Income previously reported for the year ended December 31, 2002 are as follows:
AS PREVIOUSLY AS REPORTED RESTATED -------- -------- (IN THOUSANDS) Revenues $ 2,948,675 $ 2,948,675 Expenses 2,486,990 2,494,844 Other income 42,329 42,859 ----------- ----------- Income before net interest charges 504,014 496,690 Net interest charges 140,531 140,531 Net income $ 363,483 $ 356,159 Preferred stock dividend requirements 6,510 6,510 ----------- ----------- Earnings on common stock $ 356,973 $ 349,649 =========== ===========
RESULTS OF OPERATIONS Earnings on common stock in 2002 increased 3.0% to $349.6 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 corporate restructuring 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 3 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 under corporate separation, 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 $94.8 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 ----------------------------------------------------------------------- RESTATED (SEE NOTE 1(M)) INCREASE (DECREASE) (IN MILLIONS) Fuel and purchased power..................... $(109.6) $ (84.1) Nuclear operating costs...................... (28.9) 14.7 Other operating costs........................ 51.3 (14.6) ----------------------------------------------------------------------- TOTAL OPERATION AND MAINTENANCE EXPENSES... (87.2) (84.0) Provision for depreciation and amortization.. (39.4) (140.8) General taxes................................ 23.5 (52.3) Income taxes................................. 8.3 40.4 ----------------------------------------------------------------------- TOTAL OPERATING EXPENSES AND TAXES......... $ (94.8) $(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 $51.3 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. 4 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 $39.4 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 $25.8 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. 5 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 6 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. On July 25, 2003, Standard & Poor's (S&P) issued comments on FirstEnergy's debt ratings in light of the latest extension of the Davis-Besse outage and the NJBPU decision on the JCP&L rate case. S&P noted that additional costs from the Davis-Besse outage extension, the NJBPU ruling on recovery of deferred energy costs and additional capital investments required to improve reliability in the New Jersey shore communities will adversely affect FirstEnergy's cash flow and deleveraging plans. S&P noted that it continues to assess FirstEnergy's plans to determine if projected financial measures are adequate to maintain its current rating. On August 7, 2003, S&P affirmed its "BBB" corporate credit rating for FirstEnergy. However, S&P stated that although FirstEnergy generates substantial free cash, that its strategy for reducing debt had deviated substantially from the one presented to S&P around the time of the GPU merger when the current rating was assigned. S&P further noted that their affirmation of FirstEnergy's corporate credit rating was based on the assumption that FirstEnergy would take appropriate steps quickly to maintain its investment grade ratings including the issuance of equity and possible sale of assets. Key issues being monitored by S&P included reaudit of CEI and TE by PricewaterhouseCoopers LLP, restart of Davis-Besse, FirstEnergy's liquidity position, its ability to forecast provider-of-last-resort load and the performance of its hedged portfolio, and capture of merger synergies. On August 11, 2003, S&P stated that a recent U.S. District Court ruling (see Environmental Matters below) with respect to the Sammis Plant is negative for FirstEnergy's credit quality. 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 other comprehensive income, as described in 7 Note 1 - Utility Plant and Depreciation. 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.................................. $1,848.7 $2,025.4 Penn................................ 156.9 208.8 ------------------------------------------------------------ Consolidated Total............... $2,005.6 $2,234.2 ============================================================
8 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. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning March 15, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, may have a material adverse impact on the Company's financial condition. Management is unable to predict the ultimate outcome of this matter. 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. 9 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: - Net energy generated or purchased for retail load - Losses of energy over distribution lines - Allocations to distribution companies within the FirstEnergy system - Mix of kilowatt-hour usage by residential, commercial and industrial customers - 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 10 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. Ohio Transition Cost Amortization In developing FirstEnergy's restructuring plan, the PUCO determined allowable transition costs based on amounts recorded on the EUOC's regulatory books. These costs exceeded those deferred or capitalized on FirstEnergy's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred. FirstEnergy uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company. In computing the transition cost amortization, FirstEnergy includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 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 11 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 $281 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). 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 after June 15, 2003 (OE's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. OE currently has transactions 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. OE 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 OE is currently consolidating OE 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 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 $11.6 million. 12 SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and is effective at the beginning of the first interim period beginning after June 15, 2003 (OE's third quarter of 2003) for all other financial instruments. OE did not enter into or modify any financial instruments within the scope of SFAS 150 during June 2003. Upon adoption of SFAS 150, effective July 1, 2003, OE expects to classify as debt the preferred stock of consolidated subsidiaries subject to mandatory redemptions with a carrying value of approximately $13.5 million as of June 30, 2003. Subsidiary preferred dividends on OE's Consolidated Statements of Income are currently included in net interest charges. Therefore, the application of SFAS 150 will not require the reclassification of such preferred dividends to net interest charges. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to OE's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence in a contract of a general index, such as the Consumer Price Index, would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. OE is currently assessing the new guidance and has not yet determined the impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus will be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. OE is currently assessing the new EITF consensus and has not yet determined the impact on its financial position or results of operations following adoption. 13 OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------ RESTATED (SEE NOTE 1(M)) (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)...................................... 364,436 313,177 456,246 ---------- ---------- ---------- Total operation and maintenance expenses........................... 1,703,302 1,790,541 1,241,423 Provision for depreciation and amortization.......................... 385,520 424,920 578,679 General taxes........................................................ 177,021 153,506 225,849 Income taxes......................................................... 229,001 220,678 198,436 ---------- ---------- ---------- Total operating expenses and taxes................................. 2,494,844 2,589,645 2,244,387 ---------- ---------- ---------- OPERATING INCOME........................................................ 453,831 466,819 482,321 OTHER INCOME (NOTE 1J).................................................. 42,859 68,681 55,976 ---------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES...................................... 496,690 535,500 538,297 ---------- ---------- ---------- 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.............................................................. 356,159 350,212 336,456 PREFERRED STOCK DIVIDEND REQUIREMENTS................................... 6,510 10,702 11,124 ---------- ---------- ---------- EARNINGS ON COMMON STOCK................................................ $ 349,649 $ 339,510 $ 325,332 ========== ========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 14 OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2002 2001 - ------------------------------------------------------------------------------------------------------------------ RESTATED (SEE NOTE 1(M)) (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).............................................................. 30,057 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 ---------- ---------- 1,466,583 1,108,806 ---------- ---------- DEFERRED CHARGES: Regulatory assets............................................................... 2,005,554 2,234,227 Property taxes.................................................................. 59,035 58,244 Unamortized sale and leaseback costs............................................ 72,294 75,105 Other........................................................................... 51,739 30,276 ---------- ---------- 2,188,622 2,397,852 ---------- ---------- $7,790,041 $7,915,953 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity..................................................... $2,839,255 $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 ---------- ---------- 4,172,172 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................................................................... 466,064 258,831 Accrued interest................................................................ 28,209 33,053 Other........................................................................... 74,562 63,140 ---------- ---------- 1,703,760 1,308,415 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes............................................... 1,017,629 1,175,395 Accumulated deferred investment tax credits..................................... 88,449 99,193 Nuclear plant decommissioning costs............................................. 280,858 276,500 Retirement benefits............................................................. 247,531 166,594 Other........................................................................... 279,642 269,539 ---------- ---------- 1,914,109 1,987,221 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 2 and 5)................................................................. ---------- ---------- $7,790,041 $7,915,953 ========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. 15 OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION
AS OF DECEMBER 31, 2002 2001 - ---------------------------------------------------------------------------------------------------------------------------- RESTATED (SEE NOTE 1(M)) (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)............................................. (59,495) -- Retained earnings (Note 3A)................................................................ 800,021 572,272 ---------- ---------- Total common stockholder's equity...................................................... 2,839,255 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 ======= ========= ======= --------- ----------
16 OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (CONT'D)
AS OF DECEMBER 31, 2002 2001 2002 2001 2002 2001 - ----------------------------------------------------------------------------------------------------------------------------------- RESTATED (SEE NOTE 1(M)) (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)... 8,249 10,718 ---------- ---------- Net unamortized discount on debt..... (2,084) (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................. $4,172,172 $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. 17 OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
ACCUMULATED OTHER COMPREHENSIVE NUMBER CARRYING COMPREHENSIVE RETAINED INCOME OF SHARES VALUE INCOME (LOSS) EARNINGS ------------- --------- -------- ------------- -------- RESTATED RESTATED RESTATED (SEE NOTE 1(M)) (SEE NOTE 1(M)) (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....................................... $356,159 356,159 Minimum liability for unfunded retirement benefits, net of $(45,525,000) of income taxes (64,585) (64,585) Unrealized gain on investments, net of $3,582,000 of income taxes..................... 5,090 5,090 ---------- Comprehensive income............................. $296,664 ======== Cash dividends on preferred stock................ (6,510) Cash dividends on common stock................... (121,900) - ------------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002.......................... 100 $2,098,729 $(59,495) $800,021 ===============================================================================================================================
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. 18 OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------ RESTATED (SEE NOTE 1(M)) (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income............................................................... $ 356,159 $ 350,212 $ 336,456 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization......................... 385,520 424,920 578,679 Nuclear fuel and lease amortization................................. 47,597 45,417 52,232 Deferred income taxes, net.......................................... (61,987) (63,945) (110,038) Investment tax credits, net......................................... (13,732) (13,346) (25,035) Receivables......................................................... (41,584) (61,246) (279,575) Materials and supplies.............................................. (9,930) 64,177 (7,625) Accounts payable.................................................... 182,229 (53,588) 70,089 Other (Note 7)...................................................... 212,929 (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. 19 OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF TAXES
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------ RESTATED (SEE NOTE 1(M)) (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............................................................. $ 280,587 $ 265,305 $ 329,616 State............................................................... 55,796 51,121 18,037 ----------- ----------- ----------- 336,383 316,426 347,653 ----------- ----------- ----------- Deferred, net- Federal............................................................. (44,552) (56,105) (102,692) State............................................................... (22,184) (7,840) (7,346) ----------- ----------- ----------- (66,736) (63,945) (110,038) ----------- ----------- ----------- Investment tax credit amortization..................................... (13,732) (13,346) (25,035) ----------- ----------- ----------- Total provision for income taxes.................................. $ 255,915 $ 239,135 $ 212,580 =========== =========== =========== INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating income....................................................... $ 229,001 $ 220,678 $ 198,436 Other income........................................................... 26,914 18,457 14,144 ----------- ----------- ----------- Total provision for income taxes.................................. $ 255,915 $ 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.......................... $ 612,074 $ 589,347 $ 549,036 =========== =========== =========== Federal income tax expense at statutory rate........................... $ 214,225 $ 206,271 $ 192,163 Increases (reductions) in taxes resulting from- Amortization of investment tax credits.............................. (13,732) (13,346) (25,035) State income taxes, net of federal income tax benefit............... 21,848 28,133 6,949 Amortization of tax regulatory assets............................... 30,659 32,020 39,746 Other, net.......................................................... 2,915 (13,943) (1,243) ----------- ----------- ----------- Total provision for income taxes.................................. $ 255,915 $ 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.......................................... 527,502 675,652 755,607 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............................................. (41,570) -- -- Other (Note 7)......................................................... 84,313 64,886 30,697 ----------- ----------- ----------- Net deferred income tax liability................................. $ 1,017,629 $ 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. 20 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include Ohio Edison Company (Company) and its wholly owned subsidiaries. Pennsylvania Power Company (Penn) is the Company's principal operating subsidiary. 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. 21 Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 560 megawatts (MW) of generation capacity through 2005 at established prices for sales to the Company's retail customers. Customer prices are frozen through the five-year market development period 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 expense costs and 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. 22 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 was $298 million. As of December 31, 2002, the Companies have recorded decommissioning liabilities of $281 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). (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- If 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. 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 Companies' stock options would not materially effect net income. 23 (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, FirstEnergy 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. 24 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 25 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 =============================================================================================
26 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 in other comprehensive income. 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 $282 million in 2002 and $274 million 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 - ----------------------------------------------------------------------------------------------------- RESTATED (SEE NOTE 1(M)) (IN MILLIONS) Regulatory transition costs........................................... $1,840.4 $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.......................................................... $2,005.6 $2,234.2 =====================================================================================================
(M) RESTATED FINANCIAL STATEMENTS The Company has restated its financial statements for the year ended December 31, 2002, to reflect a change in the method of amortizing the costs associated with the Ohio transition plan. The Company amortizes transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred and are not reflected as regulatory assets in the financial statements prepared under generally accepted accounting principles (GAAP). OE has revised the amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period compared with the method previously applied. The change in method results in no change in total amortization of the regulatory assets recovered through the transition period, which is expected to end in 2006. 27 After giving effect to the restatement, total transition cost amortization (including above market leases) is expected to approximate the following for the years from 2003 through 2006 (in millions). 2003.............. $389 2004.............. 456 2005.............. 553 2006.............. 178
The change in amortization resulted in a decrease in net income of $5.4 million and included an increase in net income of $15.4 million from the cumulative impact of the adjustments related to 2001 and a $20.8 million decrease in net income for additional amortization expense in 2002. The net adjustment is reflected as an increase of $14.7 million in depreciation and amortization expense and a decrease of $9.3 million in income tax expense in the accompanying consolidated statement of income as restated. The Company has also included in this restatement certain immaterial adjustments that were not previously recognized in 2002. The impact of these adjustments reduced net income reported for 2002 by $1.9 million. The total decrease to net income of $7.3 million resulting from these adjustments impacted the Consolidated Statement of Income previously reported for the year ended December 31, 2002 as follows:
AS PREVIOUSLY AS REPORTED RESTATED -------- -------- (IN THOUSANDS) Revenues $2,948,675 $2,948,675 Expenses 2,486,990 2,494,844 Other income 42,329 42,859 ---------- ---------- Income before net interest charges 504,014 496,690 Net interest charges 140,531 140,531 ---------- ---------- Net income $ 363,483 $ 356,159 Preferred stock dividend requirements 6,510 6,510 ---------- ---------- Earnings on common stock $ 356,973 $ 349,649 ========== ==========
The change in the amortization method and the other adjustments had the following impact on the Consolidated Balance Sheet as of December 31, 2002:
INCREASE (DECREASE): (IN THOUSANDS) Current assets $ (3,500) Regulatory assets (7,200) ---------- Total assets $ (10,700) ========== Current liabilities $ (1,032) Deferred income taxes (8,562) Common stockholders equity (1,106) ---------- Capitalization and liabilities $ (10,700) ==========
Net cash provided from operating activities remained unchanged at approximately $1.1 billion in 2002. 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 28 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 $800.0 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 29 (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
30 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 sinking and improvement fund requirements for all bonds issued under the various mortgage indentures of the Companies amounts to $39 million. The Companies expect to deposit funds with their respective mortgage bond trustees in 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. 31 (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 gains on investments in securities available for sale of $5.1 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. 32 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 (see Note 9). 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. 33 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 $11.6 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..................................... (29,909) (76,858) (9,392) - ----------------------------------------------------------------------------------- Total-Other................................. $212,929 $ (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 ================================================================================
34 8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
THREE MONTHS ENDED MARCH 31, 2002 (A) JUNE 30, 2002 (A) SEPTEMBER 30, 2002 (A) DECEMBER 31, 2002 (A) - --------------------------------------------------------------------------------------------------------------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED (IN MILLIONS) Operating Revenues $707.8 $707.8 $744.5 $744.5 $813.3 $813.3 $683.1 $683.1 Operating Expenses and Taxes 610.7 600.4 605.9 611.1 658.8 664.5 611.6 618.8 Operating Income 97.1 107.4 138.6 133.4 154.5 148.8 71.5 64.2 - --------------------------------------------------------------------------------------------------------------------------------- Other Income 0.5 0.5 15.1 15.1 14.2 14.2 12.5 13.0 Net Interest Charges 41.2 41.2 35.9 35.9 33.7 33.7 29.7 29.8 Net Income $ 56.4 66.7 $117.8 112.6 135.0 129.3 54.3 47.5 - --------------------------------------------------------------------------------------------------------------------------------- Earnings on Common Stock $ 53.8 $ 64.0 $115.2 $110.1 $134.4 $128.6 $ 53.6 $ 46.9 =================================================================================================================================
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 ================================================================================================
(a) See Note 1(M) for discussion of restated financial data. 9. SUBSEQUENT EVENTS ENVIRONMENTAL MATTERS- On August 8, 2003, FirstEnergy, OE and Penn reported a development regarding a complaint filed by the U.S. Department of Justice with respect to the W.H. Sammis Plant (see Note 5(C) Commitments and Contingencies - Environmental Matters). As reported, on August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning March 15, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." Management is unable to predict the ultimate outcome of this matter. The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, may have a material adverse impact on the Company's financial condition. Management is unable to predict the ultimate outcome of this matter. The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, may have a material adverse impact on the Company's financial condition. RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET IMPLEMENTED- SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and is effective at the beginning of the first interim period beginning after June 15, 2003 (OE's third quarter of 2003) for all other financial instruments. OE did not enter into or modify any financial instruments within the scope of SFAS 150 during June 2003. Upon adoption of SFAS 150, effective July 1, 2003, OE expects to classify as debt the preferred stock of consolidated subsidiaries subject to mandatory redemptions with a carrying value of approximately $13.5 million as of June 30, 2003. Subsidiary preferred dividends on OE's Consolidated Statements of Income are currently included in net interest 35 charges. Therefore, the application of SFAS 150 will not require the reclassification of such preferred dividends to net interest charges. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to OE's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence in a contract of a general index, such as the Consumer Price Index, would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. OE is currently assessing the new guidance and has not yet determined the impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus will be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. OE is currently assessing the new EITF consensus and has not yet determined the impact on its financial position or results of operations following adoption. 36 REPORT OF INDEPENDENT AUDITORS 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 auditors who have ceased operations. Those independent auditors expressed an unqualified opinion on those financials statements in their report dated March 18, 2002. As discussed in Note 1(M) to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements for the year ended December 31, 2002. PricewaterhouseCoopers LLP Cleveland, Ohio February 28, 2003, except as to Note 1(M), which is as of August 18, 2003 37 The following report is a copy of a report previously issued by Arthur Andersen LLP (Andersen). This report has not been reissued by Andersen and Andersen did not consent to the incorporation by reference of this report (as included in this Form 10-K/A) into any of the Company's registration statements. 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. 38 EX-23.1 11 l02705aexv23w1.txt EXHIBIT 23.1 EXHIBIT 23.1 OHIO EDISON COMPANY CONSENT OF INDEPENDENT AUDITORS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 33-49413, 33-51139, 333-01489 and 333-05277) of Ohio Edison Company of our report dated February 28, 2003, except as to Note 1(M), which is as of August 18, 2003, relating to the consolidated financial statements, which appears in the restated Annual Report to Stockholders, which is incorporated in this Annual Report on Form 10-K/A. PricewaterhouseCoopers LLP Cleveland, Ohio August 18, 2003 58 EX-12.3 12 l02705aexv12w3.txt EXHIBIT 12.3 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 -------- -------- -------- -------- -------- RESTATED RESTATED RESTATED RESTATED RESTATED (DOLLARS IN THOUSANDS) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items ................ $175,765 $204,963 $210,424 $177,905 $136,952 Interest and other charges, before reduction for amounts capitalized ............................ 232,727 211,960 201,739 192,102 189,502 Provision for income taxes ....................... 121,937 135,195 138,426 137,887 84,938 Interest element of rentals charged to income (a) 68,314 66,680 65,616 59,497 51,170 -------- -------- -------- -------- -------- Earnings as defined ............................ $598,743 $618,798 $616,205 $567,391 $450,662 ======== ======== ======== ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K: Interest expense ................................. $232,727 $211,960 $201,739 $191,727 180,602 Subsidiary's preferred stock dividend requirements -- -- -- 375 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 $267,355 $251,599 $240,672 ======== ======== ======== ======== ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES ..... 1.99 2.22 2.30 2.26 1.92 ======== ======== ======== ======== ========
- ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined. 53 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 -------- -------- -------- -------- -------- RESTATED RESTATED RESTATED RESTATED RESTATED (DOLLARS IN THOUSANDS) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items ...................... $175,765 $204,963 $210,424 $177,905 $136,952 Interest and other charges, before reduction for amounts capitalized .......................................... 232,727 211,960 201,739 192,102 189,502 Provision for income taxes ............................. 121,937 135,195 138,426 137,887 84,938 Interest element of rentals charged to income (a) ...... 68,314 66,680 65,616 59,497 51,170 -------- -------- -------- -------- -------- Earnings as defined .................................. $598,743 $618,798 $616,205 $567,391 $462,562 ======== ======== ======== ======== ======== FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS): Interest expense ....................................... $232,727 $211,960 $201,739 $191,727 $180,602 Preferred stock dividend requirements .................. 24,794 33,524 20,843 25,213 24,590 Adjustments to preferred stock dividends to state on a pre-income tax basis ................... 16,632 21,395 13,012 18,714 15,406 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 $301,210 $295,151 $271,768 ======== ======== ======== ======== ======== CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS) ................................. 1.75 1.86 2.05 1.92 1.70 ======== ======== ======== ======== ========
- ------------------------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined. 54 EX-13.2 13 l02705aexv13w2.txt EXHIBIT 13.2 EXHIBIT 13.2 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............................... 2-15 Consolidated Statements of Income.................................. 16 Consolidated Balance Sheets........................................ 17 Consolidated Statements of Capitalization.......................... 18-19 Consolidated Statements of Common Stockholder's Equity............. 20 Consolidated Statements of Preferred Stock......................... 20 Consolidated Statements of Cash Flows.............................. 21 Consolidated Statements of Taxes................................... 22 Notes to Consolidated Financial Statements......................... 23-40 Report of Independent Auditors..................................... 41
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY SELECTED FINANCIAL DATA (RESTATED*)
2002 2001 2000 1999 1998 ---------- ---------- ---------- ---------- ---------- (DOLLARS IN THOUSANDS) GENERAL FINANCIAL INFORMATION: Operating Revenues ..................... $1,843,671 $2,064,622 $1,890,339 $1,864,954 $1,795,997 ========== ========== ========== ========== ========== Operating Income ....................... $ 306,152 $ 354,422 $ 397,568 $ 405,640 $ 393,397 ========== ========== ========== ========== ========== Net Income ............................. $ 136,952 $ 177,905 $ 210,424 $ 204,963 $ 175,765 ========== ========== ========== ========== ========== Earnings on Common Stock ............... $ 121,262 $ 153,067 $ 189,581 $ 171,439 $ 150,971 ========== ========== ========== ========== ========== Total Assets ........................... $6,510,243 $6,526,596 $6,756,921 $6,189,261 $6,307,683 ========== ========== ========== ========== ========== CAPITALIZATION AT DECEMBER 31: Common Stockholder's Equity ............ $1,200,234 $1,073,041 $1,095,874 $ 990,177 $1,020,925 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 ................... $3,376,660 $3,477,126 $3,994,996 $4,027,543 $4,297,162 ========== ========== ========== ========== ========== CAPITALIZATION RATIOS: Common Stockholder's Equity ............ 35.5% 30.9% 27.4% 24.6% 23.8% Preferred Stock- Not Subject to Mandatory Redemption . 2.9 4.1 6.0 5.9 5.5 Subject to Mandatory Redemption ..... 3.1 3.0 0.6 2.9 3.5 Long-Term Debt ......................... 58.5 62.0 66.0 66.6 67.2 ---------- ---------- ---------- ---------- ---------- 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
* See Note 1(M) to the Consolidated Financial Statements. 1 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate", "potential," "expect", "believe", "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), availability and cost of capital, inability of the Davis-Besse Nuclear Power Station to restart (including because of an inability to obtain a favorable final determination from the Nuclear Regulatory Commission) in the fall of 2003, inability to accomplish or realize anticipated benefits from strategic goals, further investigation into the causes of the August 14, 2003, power outage, and other similar factors. 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. 2 RESTATEMENTS As further discussed in Note 1(M) to the Consolidated Financial Statements, the Company is restating its consolidated financial statements for the three years ended December 31, 2002. The revisions principally reflect a change in the method of amortizing costs being recovered through the Ohio transition plan and recognition of above-market values of certain leased generation facilities. Transition Cost Amortization As discussed under Regulatory Plan in Note 1(C) to the Consolidated Financial Statements, CEI recovers transition costs, including regulatory assets, through an approved transition plan filed under Ohio's electric utility restructuring legislation. The plan, which was approved in July 2000, provides for the recovery of costs from January 1, 2001 through a fixed number of kilowatt-hour sales to all customers that continue to receive regulated transmission and distribution service, which is expected to end in 2009. The Company amortizes transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments), but not in the financial statements prepared under generally accepted accounting principles (GAAP). The Company has revised the amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets the first several years of the transition cost recovery period, compared with the method previously applied. The change in method results in no change in total amortization of previously recorded regulatory assets recovered under the transition period through the end of 2009. Above-Market Lease Costs In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior Energy Corporation (Centerior). The merger was accounted for as an acquisition of Centerior, the parent company of CEI, under the purchase accounting rules of Accounting Principles Board (APB) Opinion No. 16. In connection with the reassessment of the accounting for the transition plan, the Company reassessed its accounting for the Centerior purchase and determined that above-market lease liabilities should have been recorded at the time of the merger. Accordingly, the Company has restated its financial statistics to record additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which CEI had previously entered into sale-leaseback arrangements. The Company recorded an increase in goodwill related to the above-market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional consideration would have increased goodwill at the date of the merger. The corresponding impact of the above-market lease liability for the Bruce Mansfield Plant was recorded as a regulatory asset because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided under the transition plan. The total above-market lease obligation of $611 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017 (approximately $31.2 million annually). The additional goodwill has been recorded effective as of the merger date, and amortization has been recorded through 2001, when goodwill amortization ceased with the adoption of Statement of Financial Accounting Standards (SFAS) No. 142 (SFAS 142), "Goodwill and Other Intangible Assets." The total above-market lease obligation of $457 million associated with the Bruce Mansfield Plant is being reversed through the end of 2016 (approximately $29.0 million annually). Before the start of the transition plan in fiscal 2001, the regulatory asset would have been amortized at the same rate as the lease obligation resulting in no impact to net income. Beginning in 2001, the unamortized regulatory asset has been included in the Company's revised amortization schedule for regulatory assets and amortized through the end of the recovery period in 2009. The Company has reflected the impact of the accounting for the period from the merger in 1997 through 1999 as a cumulative effect adjustment of $23.6 million to retained earnings as of January 1, 2000. The after-tax effects of these items in the three years ended December 31, 2002, were as follows: 3
INCOME STATEMENT EFFECTS - ------------------------ INCREASE (DECREASE) TRANSITION REVERSAL COST OF LEASE AMORTIZATION OBLIGATIONS(1) TOTAL ------------ -------------- --------- (IN THOUSANDS) Year ended December 31, 2002 Nuclear operating expenses ................ $ -- $ (31,200) $ (31,200) Other operating expenses .................. -- (29,000) (29,000) Provision for depreciation and amortization 52,000 51,300 103,300 Income taxes .............................. (21,945) 3,744 (18,201) ------------ -------------- --------- Total expense ............................. $ 30,055 $ (5,156) $ 24,899 ============ ============== ========= Net income effect ......................... $ (30,055) $ 5,156 $ (24,899) ============ ============== ========= Year ended December 31, 2001 Nuclear operating expenses ................ $ -- $ (31,200) $ (31,200) Other operating expenses .................. -- (29,000) (29,000) Provision for depreciation and amortization 53,600 56,100 109,700 Income taxes .............................. (18,714) 1,412 (17,302) ------------ -------------- --------- Total expense ............................. $ 34,886 $ (2,688) $ 32,198 ============ ============== ========= Net income effect ......................... $ (34,886) $ 2,688 $ (32,198) ============ ============== ========= Year ended December 31, 2000 Nuclear operating expenses ................ $ -- $ (31,200) $ (31,200) Other operating expenses .................. -- -- -- Provision for depreciation and amortization -- 9,000 9,000 Income taxes .............................. -- 12,974 12,974 ------------ -------------- --------- Total expense ............................. $ -- $ (9,226) $ (9,226) ============ ============== ========= Net income effect ......................... $ -- $ 9,226 $ 9,226 ============ ============== =========
(1) The provision for depreciation and amortization in each of 2001 and 2000 includes goodwill amortization of $9.0 million. In addition, the impact increased the following balances in the Consolidated Balance Sheet as of January 1, 2000: (IN THOUSANDS) Goodwill $ 340,990 Regulatory assets 457,000 --------- Total assets $ 797,990 ========= Other current liabilities $ 60,000 Deferred income taxes (225,971) Other deferred credits 940,400 --------- Total liabilities $ 774,429 ========= Retained earnings $23,561 =======
The impact of the adjustments described above for the next five years is expected to reduce net income in 2003 through 2005 and increase net income in 2006 through 2007 as shown below.
CHANGE IN REGULATORY LEASE EFFECT ON EFFECT TRANSITION COST ASSET LIABILITY PRE-TAX ON NET YEAR AMORTIZATION AMORTIZATION (A) REVERSAL INCOME INCOME ---- ------------ ---------------- -------- ------ ------ (IN MILLIONS) 2003 $(39.4) $(57.7) $60.2 $(36.9) $(21.8) 2004 (22.9) (64.8) 60.2 (27.5) (16.2) 2005 18.3 (74.4) 60.2 4.1 2.4 2006 (9.5) (43.7) 60.2 7.0 4.1 2007 30.4 (49.5) 60.2 41.1 24.2
(a) This represents the additional amortization related to the regulatory assets recognized in connection with the above-market lease for the Bruce Mansfield Plant discussed above. After giving effect to the restatement, total transition cost amortization (including above market leases) is expected to approximate the following for the years from 2003 through 2009 (in millions). 2003.............. $71 2004.............. 102 2005.............. 161 2006.............. 74 2007.............. 125 2008.............. 213 2009.............. 55
4 Other Unrecorded Adjustments This restatement for the three years ended December 31, 2002 also includes adjustments that were not previously recognized that principally related to an adjustment to unbilled revenues in 2001 with corresponding impact in 2002. The net income impact by year was $7.6 million in 2002, $(7.9) million in 2001 and $(1.8) million in 2000. The effects of all the changes on the Consolidated Statements of Income previously reported for the three years ended December 31, 2002 are as follows:
2002 2001 2000 -------------------------- -------------------------- -------------------------- AS PREVIOUSLY RESTATED AS PREVIOUSLY RESTATED AS PREVIOUSLY RESTATED PRESENTED PRESENTATION PRESENTED PRESENTATION PRESENTED PRESENTATION ---------- ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) Revenues ......................... $1,835,371 $1,843,671 $2,076,222 $2,064,622 $1,887,039 $1,890,339 Expenses ......................... 1,510,225 1,537,519 1,680,661 1,710,200 1,496,945 1,492,771 Other income ..................... 15,971 15,971 13,292 13,292 12,568 12,568 ---------- ---------- ---------- ---------- ---------- ---------- Income before net interest charges 341,117 321,123 408,853 367,714 402,662 410,136 Net interest charges ............. 185,171 185,171 189,809 189,809 199,712 199,712 ---------- ---------- ---------- ---------- ---------- ---------- Net income ....................... 155,946 136,952 219,044 177,905 202,950 210,424 Preferred stock dividend requirements ..................... 17,390 15,690 25,838 24,838 20,843 20,843 ---------- ---------- ---------- ---------- ---------- ---------- Earnings on common stock ......... $ 138,556 $ 121,262 $ 193,206 $ 153,067 $ 182,107 $ 189,581 ========== ========== ========== ========== ========== ==========
RESULTS OF OPERATIONS Earnings on common stock in 2002 decreased 20.8% to $121.3 million in 2002 from $153.1 million in 2001 and $189.6 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 of corporate restructuring shown in the table above, earnings on common stock decreased by 19.3% in 2001 from 2000. Operating revenues decreased $221.0 million or 10.7% in 2002 compared with 2001. The lower revenues reflected the effects of a sluggish national economy on our service area, shopping by Ohio customers for alternative energy providers and decreases in wholesale revenues. Retail kilowatt-hour sales declined by 23.9% in 2002 from the prior year, with declines in all customer sectors (residential, commercial and industrial), resulting in a $123.0 million reduction in generation sales revenue. Our lower generation kilowatt-hour sales resulted primarily from customer choice in Ohio. Sales of electric generation by alternative suppliers as a percent of total sales delivered in our franchise area 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 Corporate Restructuring table above, operating revenues decreased by $221.9 million or 11.7% 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. 5
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 $172.7 million in 2002 and increased by $217.4 million in 2001 from 2000. Excluding the effects of restructuring, total 2001 operating expenses and taxes were $173.3 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 - -------------------------------------- ------- ------- RESTATED (SEE NOTE 1(M)) INCREASE (DECREASE) (IN MILLIONS) Fuel and purchased power ........................... $(181.2) $ (145.6) Nuclear operating costs ............................ 98.7 (11.8) Other operating costs .............................. 16.5 (41.6) ------- ------- TOTAL OPERATION AND MAINTENANCE EXPENSES ......... (66.0) (199.0) Provision for depreciation and amortization ........ (59.7) 80.4 General taxes ...................................... 2.9 (64.8) Income taxes ....................................... (49.9) 10.1 ------- ------- TOTAL OPERATING EXPENSES AND TAXES ............... $(172.7) $ (173.3) ------- -------
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 $16.5 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 $11.4 million in 2001 from the prior year due to one less nuclear refueling outage in 2001. Other operating costs decreased $41.6 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 $59.7 million in 2002 from 2001 primarily due to higher shopping incentive deferrals and tax-related deferrals under our transition plan and the cessation of goodwill amortization ($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 increased by $80.4 million due to amortization of transition costs offset by 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. 6 Preferred Stock Dividend Requirements Preferred stock dividend requirements were $9.1 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. 7 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 8 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. 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) 9 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 $1,191.8 million and $1,230.2 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 fall 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). 10 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 ------
Power Outage On August 14, 2003, eight states and southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. The cause of the outage has not been determined. After having restored service to its customers, FirstEnergy is accumulating data and evaluating the status of its electrical system prior to and during the outage event. FirstEnergy is committed to working with the North American Electric Reliability Council and others involved to determine exactly what events in the entire affected region led to the outage. There is no timetable as to when this entire process will be completed. It is, however, expected to last several weeks, at a minimum 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. 11 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, the CEI's regulatory assets totaled $1,191.8 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: - Net energy generated or purchased for retail load - Losses of energy over distribution lines - Allocations to distribution companies within the FirstEnergy system - Mix of KWH usage by residential, commercial and industrial customers - 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 12 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. Ohio Transition Cost Amortization In developing CEI's restructuring plan, the PUCO determined allowable transition costs based on amounts recorded on the EUOC's regulatory books. These costs exceeded those deferred or capitalized on CEI's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). The Company uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for CEI. In computing the transition cost amortization, CEI includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 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). 13 Goodwill The Regulators in the jurisdictions that CEI operates does not provide for recovery of goodwill. As a result, no amortization of goodwill has been recorded subsequent to the adoption of SFAS 142. 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 $1.7 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 $242.1 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). 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. 14 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 (CEI's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. CEI currently has transactions 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. CEI currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. One of these entities CEI 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 a 0.34 percent equity interest by Toledo Edison Capital Corp., a majority owned subsidiary. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and is effective at the beginning of the first interim period beginning after June 15, 2003 (CEI's third quarter of 2003) for all other financial instruments. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence in a contract of a general index, such as the Consumer Price Index, would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. CEI is currently assessing the new guidance and has not yet determined the impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus will be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. CEI is currently assessing the new EITF consensus and has not yet determined the impact on its financial position or results of operations following adoption. 15 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME (RESTATED*)
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 - -------------------------------------------------------------------------------------------------------------- (IN THOUSANDS) OPERATING REVENUES (NOTE 1)................................. $1,843,671 $2,064,622 $1,890,339 ---------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel and purchased power (Note 1)........................ 587,108 768,306 414,127 Nuclear operating costs (Note 1)......................... 207,313 108,587 120,371 Other operating costs (Note 1)........................... 279,242 262,745 381,118 ----------- ----------- ----------- Total operation and maintenance expenses............... 1,073,663 1,139,638 915,616 Provision for depreciation and amortization.............. 244,727 304,417 229,915 General taxes............................................ 147,804 144,948 222,297 Income taxes............................................. 71,325 121,197 124,943 ------------ ----------- ----------- Total operating expenses and taxes..................... 1,537,519 1,710,200 1,492,771 ---------- ---------- ---------- OPERATING INCOME............................................ 306,152 354,422 397,568 OTHER INCOME (NOTE 1)....................................... 15,971 13,292 12,568 ------------ ------------ ------------ INCOME BEFORE NET INTEREST CHARGES.......................... 322,123 367,714 410,136 ----------- ----------- ----------- 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.................................................. 136,952 177,905 210,424 PREFERRED STOCK DIVIDEND REQUIREMENTS............................................. 15,690 24,838 20,843 ------------ ------------ ------------- EARNINGS ON COMMON STOCK.................................... $ 121,262 $ 153,067 $ 189,581 =========== =========== ===========
* See Note 1(M) The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 16 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (RESTATED*)
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 9,406 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 ---------- ---------- 311,127 265,343 ---------- ---------- DEFERRED CHARGES: Regulatory assets ........................................................... 1,191,804 1,230,288 Goodwill .................................................................... 1,693,629 1,693,629 Property taxes .............................................................. 79,430 80,470 Other ....................................................................... 24,798 8,297 ---------- ---------- 2,989,661 3,012,684 ---------- ---------- $6,510,243 $6,526,596 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity ................................................. $1,200,001 $1,082,041 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 ---------- ---------- 3,376,427 3,486,126 ---------- ---------- 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 .............................................................. 126,261 124,677 Accrued interest ............................................................ 51,767 57,101 Other ....................................................................... 124,624 124,264 ---------- ---------- 1,261,672 1,042,171 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes ........................................... 407,297 413,638 Accumulated deferred investment tax credits ................................. 70,803 75,435 Nuclear plant decommissioning costs ......................................... 242,511 206,698 Pensions and other postretirement benefits .................................. 171,968 231,365 Deferred lease costs ........................................................ 788,800 849,000 Other ....................................................................... 190,765 222,163 ---------- ---------- 1,872,144 1,998,299 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 2 and 5) ---------- ---------- $6,510,243 $6,526,299 ========== ==========
* See Note 1(M) The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. 17 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (RESTATED*)
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)..................................... (44,284) 9,000 Retained earnings (Note 3A)........................................................ 262,323 141,079 ---------- ---------- Total common stockholder's equity................................................ 1,200,001 1,082,041 ---------- ----------
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 ---------- ----------
* See Note 1(M) 18 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (RESTATED*)(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 ................ $ 3,376,427 $ 3,486,126 =========== ===========
* See Note 1(M). **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. 19 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (RESTATED)
ACCUMULATED OTHER COMPREHENSIVE NUMBER CARRYING COMPREHENSIVE RETAINED INCOME OF SHARES VALUE INCOME (LOSS) EARNINGS ------ --------- ----- ------------- -------- RESTATED RESTATED (SEE NOTE 1(M)) (SEE NOTE 1(M)) (DOLLARS IN THOUSANDS) Balance, January 1, 2000....................... 79,590,689 $931,962 $ -- $ 34,654 Cumulative effect for restatements (see Note 1(M))........................... 23,561 - -------------------------------------------------------------------------------------------------------------------------------- Restated Balance at January 1, 2000............ 58,215 Net income.................................. $ 210,424 210,424 ========= Cash dividends on preferred stock........... (20,727) Cash dividends on common stock.............. (84,000) - -------------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000..................... 79,590,689 931,962 -- 163,912 Net income.................................. $ 177,905 177,905 --------- Unrealized gain on instruments, net of $5,900 of income taxes.................... 9,000 --------- Comprehensive income........................ $ 186,905 ========= Cash dividends on preferred stock........... (24,838) Cash dividends on common stock.............. (175,900) - -------------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001..................... 79,590,689 931,962 9,000 141,079 Net income.................................. $ 136,952 136,952 Unrealized loss on investments, net of $(6,058) of income taxes.................. (9,233) (9,233) Minimum liability for unfunded retirement benefits, net of $(31,359,000) of income taxes.................................... (44,051) (44,051) --------- Comprehensive income........................ $ 83,668 ========= Equity contribution from parent............. 50,000 Cash dividends on preferred stock........... (10,965) Preferred stock redemption premiums......... (4,743) - -------------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002..................... 79,590,689 $981,962 $(44,284) $ 262,323 ===============================================================================================================================
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 ========================================================================================
* See Note 1(M). The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 20 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (RESTATED*)
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------ (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income .................................................. $ 136,952 $ 177,905 $ 210,424 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization ............ 244,727 304,417 229,915 Nuclear fuel and lease amortization .................... 21,044 30,539 37,217 Other amortization ..................................... (15,008) (14,071) (11,635) Deferred income taxes, net ............................. 3,637 32,741 32,726 Investment tax credits, net ............................ (4,632) (3,770) (3,617) Receivables ............................................ (27,159) 42,542 (20,175) Materials and supplies ................................. (7,624) 15,949 (1,697) Accounts payable ....................................... 47,147 (52,068) 20,817 Deferred lease costs ................................... (60,200) (60,200) (31,200) Accrued taxes .......................................... (3,568) (48,877) 3,074 Accrued interest ....................................... (5,334) 959 (4,598) Prepayments and other .................................. 27,418 27,743 (2,930) Other .................................................. (40,245) (88,314) (32,061) --------- --------- --------- 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 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 ....................................................... (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 ========= ========= =========
* See Note 1(M). The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 21 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF TAXES (RESTATED*)
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 ............................................. $ 76,364 $ 92,739 $ 108,024 State ............................................... 14,721 16,177 1,294 --------- --------- --------- 91,085 108,916 109,318 --------- --------- --------- Deferred, net- Federal ............................................. (3,661) 32,368 31,097 State ............................................... 2,146 1,125 1,629 --------- --------- --------- (1,515) 33,493 32,726 --------- --------- --------- Investment tax credit amortization ..................... (4,632) (4,522) (3,617) --------- --------- --------- Total provision for income taxes ................ $ 84,938 $ 137,887 $ 138,427 ========= ========= ========= INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating income ....................................... $ 71,325 $ 121,197 $ 124,943 Other income ........................................... 13,613 16,690 13,484 --------- --------- --------- Total provision for income taxes ................ $ 84,938 $ 137,887 $ 138,427 ========= ========= ========= RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes .......... $ 221,890 $ 315,792 $ 348,851 ========= ========= ========= Federal income tax expense at statutory rate ........... $ 77,662 $ 110,527 $ 122,098 Increases (reductions) in taxes resulting from- State income taxes, net of federal income tax benefit 10,964 11,246 1,900 Amortization of investment tax credits .............. (4,632) (4,522) (3,617) Amortization of tax regulatory assets ............... 999 1,012 693 Amortization of goodwill ............................ -- 16,530 16,509 Other, net .......................................... (55) 3,094 844 --------- --------- --------- Total provision for income taxes ................ $ 84,938 $ 137,887 $ 138,427 ========= ========= ========= ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences ............................. $ 473,506 $ 463,344 $ 495,588 Competitive transition charge .......................... 371,486 424,484 320,618 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 ............................. (31,517) 5,900 -- Above market leases .................................... (350,299) (375,333) (400,367) Retirement Benefits .................................... (42,079) (73,483) (62,594) All other .............................................. (29,154) (51,481) 38,758 --------- --------- --------- Net deferred income tax liability ............... $ 407,297 $ 413,638 $ 376,130 ========= ========= =========
* See Note 1(M). ** 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. 22 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, 23 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 (see Note 1(M)) 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. See Note 1(M) for further discussion of the Ohio transition plan. (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. 24 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 $242.4. 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 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 $47.2 million of goodwill annually. The goodwill balance as of December 31, 2002 and 2001 was $1.694 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.............................. $136,952 $177,905 $210,424 Add back goodwill amortization................... -- 47,230 47,170 -------- -------- -------- Adjusted net income.............................. $136,952 $225,135 $257,594 ======== ======== ========
(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 . =================================================================================================
25 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 26 $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. 27 (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: 28
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. 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 ---- ---- REVISED ------- (SEE NOTE 1(M)) --------------- (IN MILLIONS) Regulatory transition charge.................... $1,151.0 $1,186.1 Customer receivables for future income taxes.... 8.0 9.2 Loss on reacquired debt......................... 15.7 16.5 Other........................................... 17.1 18.5 -------------------------------------------------------------------------- Total...................................... $1,191.8 $1,230.3 ==========================================================================
(M) RESTATEMENTS The Company is restating its financial statements for the three years ended December 31, 2002. The primary modifications include revisions to reflect a change in the method of amortizing costs being recovered through the Ohio transition plan and recognition of above-market values of certain leased generation facilities. In addition, certain other immaterial previously unrecorded adjustments are now reflected in results for the three years ended December 31, 2002. 29 Transition Cost Amortization - The Company amortizes transition costs, described in Note 1(C) above, using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements but not in the financial statements prepared under GAAP. CEI has revised the amortization schedule under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets the first several years of the transition cost recovery period, compared with the method previously applied. The change in method results in no change in total amortization of the regulatory assets previously recoded recovered under the transition period through the end of 2009. Above-Market Lease Costs - In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior. The merger was accounted for as an acquisition of Centerior, the parent company of CEI, under the purchase accounting rules of APB 16. In connection with the reassessment of the accounting for the transition plan, the Company reassessed its accounting for the Centerior purchase and determined that above-market lease liabilities should have been recorded at the time of the merger. Accordingly, the Company has restated its financial status to record additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which CEI had previously entered into sale-leaseback arrangements. The Company recorded an increase in goodwill related to the above-market lease costs for Beaver Valley Unit 2 because regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional consideration would have increased goodwill at the date of the merger. The corresponding impact of the above-market lease liability for the Bruce Mansfield Plant was recorded as a regulatory asset because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided under the Company's Regulatory Plan in effect at the time of the merger and subsequently under the transition plan. The total above-market lease obligation of $611 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017 (approximately $31.2 million annually). The additional goodwill has been recorded effective as of the merger date, and amortization has been recorded through 2001, when goodwill amortization ceased with the adoption of SFAS 142. The total above-market lease obligation of $457 million associated with the Bruce Mansfield Plant is being amortized through the end of 2016 (approximately $29.0 million annually). Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation resulting in no impact to net income. Beginning in 2001, the unamortized regulatory asset has been included in the Company's revised amortization schedule for regulatory assets and amortized through the end of the recovery period in 2009. The Company has reflected the impact of the accounting for the period from the merger in 1997 through 1999 as a cumulative effect adjustment of $23.6 million to retained earnings as of January 1, 2000. The after-tax effect of these items in the three years ended December 31, 2002 was as follows: 30
INCOME STATEMENT EFFECTS - ------------------------ INCREASE (DECREASE) TRANSITION ABOVE COST MARKET LEASES AMORTIZATION (1) TOTAL ------------ -------------- ----- (IN THOUSANDS) Year ended December 31, 2002 Nuclear operating expenses $ -- $(31,200) $ (31,200) Other operating expenses -- (29,000) (29,000) Provision for depreciation and amortization 52,000 51,300 103,300 -------- -------- --------- Income taxes (21,945) 3,744 (18,201) -------- -------- --------- Total expense $ 30,055 $ (5,156) $ 24,899 ======== ======== ========= Net income effect $(30,055) $ 5,156 $ (24,899) ======== ======== ========= Year ended December 31, 2001 Nuclear operating expenses $ -- $(31,200) $ (31,200) Other operating expenses -- (29,000) (29,000) Provision for depreciation and amortization 53,600 56,100 109,700 -------- -------- --------- Income taxes (18,714) 1,412 (17,302) -------- -------- --------- Total expense $ 34,886 $ (2,688) $ 32,198 ======== ======== ========= Net income effect $(34,886) $ 2,688 $ (32,198) ======== ======== ========= Year ended December 31, 2000 Nuclear operating expenses $ -- $(31,200) $ (31,200) Other operating expenses -- -- -- Provision for depreciation and amortization -- 9,000 9,000 -------- -------- --------- Income taxes -- 12,974 12,974 -------- -------- --------- Total expense $ -- $ (9,226) $ (9,226) ======== ======== ========= Net income effect $ -- $ 9,226 $ 9,226 ======== ======== =========
(1) The provision for depreciation and amortization in each of 2001 and 2000 includes goodwill amortization of $9.0 million. In addition, the impact increased the following balances in the Consolidated Balance Sheet as of January 1, 2000:
(in thousands) Goodwill $ 340,990 Regulatory assets 457,000 --------- Total assets $ 797,990 ========= Other current liabilities $ 60,000 Deferred income taxes (225,971) Other deferred credits 940,400 --------- Total liabilities $ 774,429 ========= Retained earnings $ 23,561 =========
The impact of the adjustments described above for the next five years is expected to reduce net income in 2003 through 2005 and increase net income in 2006 through 2007. After giving effect to the restatement, total transition cost amortization (including above market leases) is expected to approximate the following for the years from 2003 through 2007 (in millions). 2003.............. $ 71 2004.............. 102 2005.............. 161 2006.............. 74 2007.............. 125 2008.............. 213 2009.............. 55
31 Other Unrecorded Adjustments This restatement for the three years ended December 31, 2002 also includes adjustments that were not previously recognized that principally related to an adjustment to unbilled revenue in 2001 with a corresponding impact in 2002. The net impact by year was $7.6 million in 2002, $(7.9) million in 2001 and $(1.8) million in 2000. The effects of all of the changes in this restatement on the previously reported Consolidated Balance Sheet as of December 31, 2002 and 2001, and the Consolidated Statements of Income and Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000 are as follows:
2002 2001 2000 ------------------------------------------------------------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED ------------------------------------------------------------------------------- (IN THOUSANDS) CONSOLIDATED STATEMENTS OF INCOME OPERATING REVENUES $1,835,371 $1,843,671 $2,076,222 $2,064,622 $ 1,887,039 $ 1,890,339 Total revenues EXPENSES: Fuel and purchased power 587,108 587,108 768,306 768,306 414,127 414,127 Nuclear operating costs 238,513 207,313 139,787 108,587 151,571 120,371 Other operating expenses 307,142 279,242 290,945 262,745 374,818 381,118 Provision for depreciation and amortization 141,427 244,727 194,717 304,417 220,915 229,915 General taxes 147,804 147,804 144,948 144,948 222,297 222,297 Income taxes 88,231 71,325 141,958 121,197 113,217 124,943 ---------- ---------- ---------- ---------- ----------- ----------- Total expenses 1,510,225 1,537,519 1,680,661 1,710,200 1,496,945 1,492,771 ---------- ---------- ---------- ---------- ----------- ----------- OPERATING INCOME 325,146 306,152 395,561 354,422 390,094 397,568 OTHER INCOME 15,971 15,971 13,292 13,292 12,568 12,568 ---------- ---------- ---------- ---------- ----------- ----------- INCOME BEFORE NET INTEREST CHARGES 341,117 322,123 408,853 367,714 402,662 410,136 NET INTEREST CHARGES 185,171 185,171 189,809 189,809 199,712 199,712 ---------- ---------- ---------- ---------- ----------- ----------- NET INCOME 155,946 136,952 219,044 177,905 202,950 210,424 PREFERRED STOCK DIVIDEND REQUIREMENT 17,390 15,690 25,838 24,838 20,843 20,843 ---------- ---------- ---------- ---------- ----------- ----------- EARNINGS ON COMMON STOCK $ 138,556 $ 121,262 $ 193,206 $ 153,067 $ 182,107 $ 189,581 ========== ========== ========== ========== =========== =========== CONSOLIDATED BALANCE SHEETS ASSETS CURRENT ASSETS $ 311,127 $ 311,127 $ 273,643 $ 265,343 PROPERTY, PLANT AND EQUIPMENT 2,419,039 2,419,039 2,433,385 2,433,385 INVESTMENTS 790,416 790,416 815,184 815,184 DEFERRED CHARGES: Regulatory assets 939,804 1,191,804 874,488 1,230,288 Goodwill 1,370,639 1,693,629 1,370,639 1,693,629 Other (Note 2I) 104,228 104,228 88,767 88,767 ---------- ---------- ---------- ---------- 2,414,671 2,989,661 2,333,894 3,012,684 ---------- ---------- ---------- ---------- $5,935,253 $6,510,243 $5,856,106 $6,526,596 ========== ========== ========== ========== LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES $1,201,373 $1,261,672 $ 983,724 $1,042,171 CAPITALIZATION Common stockholders' equity 1,226,632 1,200,234 1,082,145 1,073,041 Preferred stock of consolidated subsidiaries -- Not subject to mandatory redemption 96,404 96,404 141,475 141,475 Subject to mandatory redemption 5,021 5,021 6,288 6,288 Subsidiary-obligated mandatorily redeemable preferred securities (Note 5F) 100,000 100,000 100,000 100,000 Long-term debt 1,975,001 1,975,001 2,156,322 2,156,322 ---------- ---------- ---------- ---------- 3,403,058 3,376,660 3,486,230 3,477,126 ---------- ---------- ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes 659,044 407,455 637,339 407,738 Accumulated investment tax credit 72,125 70,803 76,187 75,435 Decommissioning liability 239,720 242,120 220,798 221,598 Other 359,933 1,151,533 451,828 1,302,528 ---------- ---------- ---------- ---------- 1,330,822 1,871,911 1,386,152 2,007,299 ---------- ---------- ---------- ---------- $5,935,253 $6,510,243 $5,856,106 $6,526,596 ========== ========== ========== ==========
32
2002 2001 2000 --------------------------------------------------------------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED --------------------------------------------------------------------------------- (IN THOUSANDS) CONSOLIDATED STATEMENTS OF CASH FLOWS CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 155,946 $ 136,952 $ 219,044 $ 177,905 $ 202,950 $ 210,424 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 141,427 244,727 194,717 304,417 220,915 229,915 Nuclear fuel and lease amortization 21,044 21,044 30,539 30,539 37,217 37,217 Other amortization, net (15,008) (15,008) (14,071) (14,071) (11,635) (11,635) Deferred lease costs -- (60,200) -- (60,200) -- (31,200) Deferred income taxes, net 19,973 3,637 46,976 32,741 22,373 32,726 Investment tax credits, net (4,062) (4,632) (3,770) (3,770) (3,617) (3,617) Receivables (27,159) (27,159) 30,942 42,542 (16,875) (20,175) Materials and supplies (7,624) (7,624) 15,949 15,949 (1,697) (1,697) Accounts payable 47,147 47,147 (45,542) (52,068) 20,817 20,817 Other (14,529) (21,729) (109,289) (108,489) (44,188) (36,515) --------- --------- --------- --------- --------- --------- NET CASH PROVIDED FROM OPERATING ACTIVITIES $ 317,155 $ 317,155 $ 365,495 $ 365,495 $ 426,260 $ 426,260 --------- --------- --------- --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES $(140,076) $(140,076) $(192,384) $(192,384) $(435,638) $(435,638) CASH FLOWS FROM INVESTING ACTIVITIES $(146,993) $(146,993) $(175,670) $(175,670) $ 11,857 $ 11,857
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 ====== ====== ======
33 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 34 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 35 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. 36 (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. 37 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 AND OTHER CONTINGENCIES 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. 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 38 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. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and is effective at the beginning of the first interim period beginning after June 15, 2003 (CEI's third quarter of 2003) for all other financial instruments. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to CEI's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence in a contract of a general index, such as the Consumer Price Index, would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. CEI is currently assessing the new guidance and has not yet determined the impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus will be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. CEI is currently assessing the new EITF consensus and has not yet determined the impact on its financial position or results of operations following adoption. 39 8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
THREE MONTHS ENDED MARCH 31, 2002(a) JUNE 30, 2002(a) SEPTEMBER 30, 2002(a) DECEMBER 31, 2002(a) - ------------------------------------------------------------------------------------------------------------------------------- AS AS AS AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED -------- -------- -------- -------- -------- -------- -------- -------- (IN MILLIONS) Operating Revenues $425.0 $433.3 $462.9 $462.9 $538.9 $538.9 $408.6 $408.6 Operating Expenses and Taxes 369.7 375.8 350.1 355.8 410.4 419.0 380.0 387.0 Operating Income 55.3 57.5 112.8 107.1 128.5 119.9 28.6 21.6 - ------------------------------------------------------------------------------------------------------------------------------- Other Income 5.2 5.2 3.4 3.4 5.6 5.6 1.8 1.8 Net Interest Charges 47.8 47.8 46.8 46.8 47.3 47.3 43.3 43.3 Net Income (Loss) $ 12.7 $ 14.9 $ 69.4 $ 63.7 $ 86.8 $ 78.2 $(12.9) $(19.8) - ------------------------------------------------------------------------------------------------------------------------------- Earnings (Loss) Applicable to Common Stock $ 4.4 $ 8.3 $ 66.3 $ 60.6 $ 83.6 $ 75.1 $(15.7) $(22.8) ===============================================================================================================================
THREE MONTHS ENDED MARCH 31, 2001(a) JUNE 30, 2001(a) SEPTEMBER 30, 2001(a) DECEMBER 31, 2001(a) - ------------------------------------------------------------------------------------------------------------------------------- AS AS AS AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED -------- -------- -------- -------- -------- -------- -------- -------- (IN MILLIONS) Operating Revenues $516.4 $513.1 $498.8 $498.8 $603.3 $603.3 $457.7 $449.4 Operating Expenses and Taxes 463.0 469.7 420.2 428.2 430.0 438.1 367.4 374.1 Operating Income 53.4 43.4 78.6 70.6 173.3 165.2 90.3 75.3 - ------------------------------------------------------------------------------------------------------------------------------- Other Income 4.4 4.4 1.1 1.1 4.0 4.0 3.7 3.7 Net Interest Charges 46.2 46.2 47.2 47.2 48.4 48.4 48.0 48.0 Net Income $ 11.6 $ 1.6 $ 32.5 $ 24.5 $128.9 $120.8 $ 46.0 $ 31.0 - ------------------------------------------------------------------------------------------------------------------------------- Earnings on common Stock $ 5.1 $ (4.9) $ 25.4 $ 17.4 $122.6 $114.5 $ 40.1 $ 26.1 ===============================================================================================================================
(a) See Note 1(M) for discussion of restated financial data. The changes are principally based on the impact of the Revised transition cost amortization and above market leases. In addition, the other adjustments discussed in Note 1(m) increased (decreased) net income for the quarterly periods as follows:
2002 2001 ---- ---- March 31 9.2 (1.9) December 31 (1.6) (6.0)
40 REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors of The Cleveland Electric Illuminating Company: In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company (a wholly owned subsidiary of FirstEnergy Corp.) and SUBSIDIARIES as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 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. As discussed in Note 1(D) to the consolidated financial statements, the Company changed its method of accounting for goodwill in 2002. As discussed in Note 1(M) to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements as of December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002. PricewaterhouseCoopers LLP Cleveland, Ohio August 18, 2003 41 EX-12.4 14 l02705aexv12w4.txt EXHIBIT 12.4 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 --------- --------- --------- --------- --------- RESTATED RESTATED RESTATED RESTATED RESTATED (DOLLARS IN THOUSANDS) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items ............... $ 106,582 $ 99,945 $ 138,144 $ 42,691 $ (5,142) Interest and other charges, before reduction for amounts capitalized ........................... 88,263 78,496 71,373 62,773 57,672 Provision for income taxes ...................... 72,696 56,821 78,778 23,401 (9,844) 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 $ 384,653 $ 220,973 $ 129,860 ========= ========= ========= ========= ========= FIXED CHARGES AS DEFINED IN REGULATION S-K: Interest expense ................................ $ 88,263 $ 78,496 $ 71,373 $ 62,773 $ 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 $ 167,731 $ 154,881 $ 144,846 ========= ========= ========= ========= ========= CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES ......................................... 1.95 1.89 2.29 1.43 0.90 ========= ========= ========= ========= =========
- ---------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined. 55 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 --------- --------- --------- --------- --------- RESTATED RESTATED RESTATED RESTATED RESTATED (DOLLARS IN THOUSANDS) EARNINGS AS DEFINED IN REGULATION S-K: Income before extraordinary items .................... $ 106,582 $ 99,945 $ 138,144 $ 42,691 $ (5,142) Interest and other charges, before reduction for amounts capitalized ................................ 88,263 78,496 71,373 62,773 57,672 Provision for income taxes ........................... 72,696 56,821 78,778 23,401 (9,844) 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 $ 384,653 $ 220,973 $ 129,860 ========= ========= ========= ========= ========= FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS): Interest expense ..................................... $ 88,263 $ 78,496 $ 71,373 $ 62,773 $ 57,672 Preferred stock dividend requirements ................ 13,609 16,238 16,247 16,135 10,756 Adjustments to preferred stock dividends to state on a pre-income tax basis ................. 8,335 10,363 10,143 10,167 4,146 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 $ 194,121 $ 181,183 $ 159,748 ========= ========= ========= ========= ========= CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS) ............................... 1.75 1.64 1.98 1.22 0.81 ========= ========= ========= ========= =========
- ---------- (a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined. 56 EX-13.3 15 l02705aexv13w3.txt EXHIBIT 13.3 EXHIBIT 13.3 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.............................. 2-15 Consolidated Statements of Income................................. 16 Consolidated Balance Sheets....................................... 17 Consolidated Statements of Capitalization......................... 18-19 Consolidated Statements of Common Stockholder's Equity............ 20 Consolidated Statements of Preferred Stock........................ 20 Consolidated Statements of Cash Flows............................. 21 Consolidated Statements of Taxes.................................. 22 Notes to Consolidated Financial Statements........................ 23-40 Report of Independent Auditors.................................... 41 THE TOLEDO EDISON COMPANY SELECTED FINANCIAL DATA (RESTATED*)
2002 2001 2000 1999 1998 --------------------------------------------------------------------------- (DOLLARS IN THOUSANDS) GENERAL FINANCIAL INFORMATION: Operating Revenues $ 996,045 $ 1,086,503 $ 954,947 $ 921,159 $ 957,037 =========== =========== =========== =========== =========== Operating Income $ 36,699 $ 85,964 $ 194,325 $ 165,809 $ 182,298 =========== =========== =========== =========== =========== Net Income (Loss) $ (5,142) $ 42,691 $ 138,144 $ 101,982 $ 108,619 =========== =========== =========== =========== =========== Earnings (Loss) on Common Stock $ (15,898) $ 26,556 $ 121,897 $ 85,744 $ 95,009 =========== =========== =========== =========== =========== Total Assets $ 2,861,614 $ 2,875,908 $ 3,010,657 $ 2,663,428 $ 3,130,355 =========== =========== =========== =========== =========== CAPITALIZATION: Common Stockholder's Equity $ 681,195 $ 629,805 $ 610,847 $ 557,853 $ 579,804 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 $ 1,364,460 $ 1,401,979 $ 1,765,040 $ 1,748,882 $ 1,873,470 =========== =========== =========== =========== =========== CAPITALIZATION RATIOS: Common Stockholder's Equity 49.9% 44.6% 34.6% 31.8% 30.9% Preferred Stock Not Subject to Mandatory Redemption 9.2 9.0 11.9 12.0 11.2 Long-Term Debt 40.9 46.4 53.5 56.2 57.9 ----- ----- ----- ----- ----- 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
* See Note 1(M) to the Consolidated Financial Statements. 1 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. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate", "potential," "expect", "believe", "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), availability and cost of capital, inability of the Davis-Besse Nuclear Power Station to restart (including because of an inability to obtain a favorable final determination from the Nuclear Regulatory Commission) in the fall of 2003, inability to accomplish or realize anticipated benefits from strategic goals, further investigation into the causes of the August 14, 2003, power outage, and other similar factors. 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. 2 RESTATEMENTS As further discussed in Note 1(M) to the Consolidated Financial Statements, the Company is restating its consolidated financial statements for the three years ended December 31, 2002. The revisions principally reflect a change in the method of amortizing costs being recovered through the Ohio transition plan and recognition of above-market values of certain leased generation facilities. Transition Cost Amortization As discussed under Regulatory Plan in Note 1(C) to the Consolidated Financial Statements, TE recovers transition costs, including regulatory assets, through an approved transition plan filed under Ohio's electric utility restructuring legislation. The plan, which was approved in July 2000, provides for the recovery of costs from January 1, 2001 through a fixed number of kilowatt-hour sales to all customers that continue to receive regulated transmission and distribution service, which is expected to end in 2007. The Company amortizes transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements, but not in the financial statements prepared under generally accepted accounting principles (GAAP). The Company has revised the amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets the first several years of the transition cost recovery period, compared with the method previously applied. The change in method results in no change in total amortization of the previously recorded regulatory assets recovered under the transition period through the end of 2007. Above-Market Lease Costs In 1997, FirstEnergy Corp. was formed through a merger between Ohio Edison Company (OE) and Centerior Energy Corporation (Centerior). The merger was accounted for as an acquisition of Centerior, the parent company of TE, under the purchase accounting rules of Accounting Principles Board (APB) Opinion No. 16. In connection with the reassessment of the accounting for the transition plan, the Company reassessed its accounting for the Centerior purchase and determined that above-market lease liabilities should have been recorded at the time of the merger. Accordingly, the Company has restated its financial statements to record additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above-market lease liability for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which TE had previously entered into sale-leaseback arrangements. The Company recorded an increase in goodwill related to the above-market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional consideration would have increased goodwill at the date of the merger. The corresponding impact of the above-market lease liability for the Bruce Mansfield Plant was recorded as a regulatory asset because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided under the transition plan. The total above-market lease obligation of $111 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017 (approximately $5.7 million annually). The additional goodwill has been recorded effective as of the merger date, and amortization has been recorded through 2001, when goodwill amortization ceased with the adoption of Statement of Financial Accounting Standards (SFAS) No. 142 (SFAS 142), "Goodwill and Other Intangible Assets." The total above-market lease obligation of $298 million associated with the Bruce Mansfield Plant is being reversed through the end of 2016 (approximately $18.9 million annually). Before the start of the transition plan in fiscal 2001, the regulatory asset would have been amortized at the same rate as the lease obligation resulting in no impact to net income. Beginning in 2001, the unamortized regulatory asset will be included in the Company's revised amortization schedule for regulatory assets and amortized through the end of the recovery period in 2007. The Company has reflected the impact of the accounting for the period from the merger in 1997 through 1999 as a cumulative effect adjustment of $4.3 million to retained earnings as of January 1, 2000. The after-tax effect of these items for the three years ended December 31, 2002 was as follows: 3 INCOME STATEMENT EFFECTS INCREASE (DECREASE)
TRANSITION ABOVE MARKET COST LEASES AMORTIZATION OBLIGATIONS(1) TOTAL ------------ -------------- ----- (IN THOUSANDS) Year ended December 31, 2002 Nuclear operating expenses$ -- $ (5,700) $ (5,700) Other operating expenses -- (18,900) (18,900) Provision for depreciation and amortization 28,400 40,200 68,600 Income taxes (12,559) (6,372) (18,931) -------- -------- -------- Total expense $ 15,841 $ 9,228 $ 25,069 ======== ======== ======== Net income effect $(15,841) $ (9,228) $(25,069) ======== ======== ======== Year ended December 31, 2001 Nuclear operating expenses $ -- $ (5,700) $ (5,700) Other operating expenses -- (18,900) (18,900) Provision for depreciation and amortization 13,600 33,000 46,600 Income taxes (5,619) (3,177) (8,796) -------- -------- -------- Total expense $ 7,981 $ 5,223 $ 13,204 ======== ======== ======== Net income effect $ (7,981) $ (5,223) $(13,204) ======== ======== ======== Year ended December 31, 2000 Nuclear operating expenses $ -- $ (5,700) $ (5,700) Other operating expenses -- -- -- Provision for depreciation and amortization -- 1,600 1,600 Income taxes -- 2,371 2,371 -------- -------- -------- Total expense $ -- $ (1,729) $ (1,729) ======== ======== ======== Net income effect $ -- $ 1,729 $ 1,729 ======== ======== ========
(1) The provision for depreciation and amortization in each of 2001 and 2000 includes goodwill amortization of $1.6 million. In addition, the impact increased the following balances in the consolidated balance sheet as of January 1, 2000:
(IN THOUSANDS) Goodwill $ 61,990 Regulatory assets 298,000 --------- Total assets $ 359,990 ========= Other current liabilities $ 24,600 Deferred income taxes (41,059) Other deferred credits 372,100 --------- Total liabilities $ 355,641 --------- Retained earnings $ 4,349 =========
The impact of the adjustments described above for the next five years is expected to reduce net income in 2003 through 2005 and increase net income in 2006 through 2007 as shown below.
CHANGE IN REGULATORY LEASE EFFECT ON EFFECT TRANSITION COST ASSET LIABILITY PRE-TAX ON NET YEAR AMORTIZATION AMORTIZATION (A) REVERSAL INCOME INCOME - ---- ------------ ---------------- -------- ------ ------ (in millions) 2003 $(15.5) $(45.3) $24.6 $(36.2) $(21.4) 2004 (7.1) (52.9) 24.6 (35.4) (20.9) 2005 9.6 (61.9) 24.6 (27.7) (16.3) 2006 20.2 (39.3) 24.6 5.5 3.2 2007 33.6 (27.0) 24.6 31.2 18.4
(a) This represents the additional amortization related to the regulatory assets recognized in connection with the above-market lease for the Bruce Mansfield Plant discussed above. After giving effect to the restatement, total transition cost amortization (including above market leases) is expected to approximate the following for the years from 2003 through 2007 (in millions). 2003........ $53 2004........ 71 2005........ 99 2006........ 76 2007........ 75
4 Other Unrecorded Adjustments This restatement for the years ended December 31, 2002, 2001 and 2000 also includes adjustments that were not previously recognized that principally related to an adjustment to unbilled revenues in 2001 with the corresponding impact in 2002. The net income impact by year was $7.2 million in 2002, $(7.0) million in 2001 and $(0.8) million in 2000. The effects of all the changes on the Consolidated Statements of Income previously reported for the three years ended December 31, 2002 are as follows:
2002 2001 2000 AS PREVIOUSLY RESTATED AS PREVIOUSLY RESTATED AS PREVIOUSLY RESTATED PRESENTED PRESENTATION PRESENTED PRESENTATION PRESENTED PRESENTATION --------- ------------ --------- ------------ --------- ------------ (IN THOUSANDS EXCEPT PER SHARE AMOUNTS) Revenues $ 987,645 $ 996,045 $1,094,903 $1,086,503 $ 954,947 $ 954,947 Expenses 932,467 959,346 989,419 1,000,539 761,533 760,622 Other income 13,329 13,329 15,652 15,652 8,669 8,669 ---------- ---------- ---------- ---------- ---------- ---------- Income before net interest charges 68,507 50,028 121,136 101,616 202,083 202,994 Net interest charges 55,170 55,170 58,225 58,925 64,850 64,850 ---------- ---------- ---------- ---------- ---------- ---------- Net income 13,337 (5,142) 62,911 42,691 137,233 138,144 Preferred stock dividend requirements 11,356 10,756 16,135 16,135 16,247 16,247 ---------- ---------- ---------- ---------- ---------- ---------- Earnings on common stock $ 1,981 $ (15,898) $ 46,776 $ 26,556 $ 120,986 $ 121,897 ========== ========== ========== ========== ========== ==========
RESULTS OF OPERATIONS Earnings on common stock decreased to a loss of $15.9 million in 2002 from $26.6 million in 2001 and $121.9 million in 2000. Excluding the effects of the corporate restructuring shown in the table above, earnings on common stock decreased by 13.2% in 2001 from 2000. Operating revenues decreased by $90.5 million or 8.3% 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 Corporate Restructuring table above, operating revenues decreased by $63.1 million or 6.6% 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. 5
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 $41.2 million in 2002 and increased by $239.9 million in 2001 from 2000. Excluding the effects of restructuring, total 2001 operating expenses and taxes were $18.0 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 - ----------------------------------------------------------------------- RESTATED (SEE NOTE 1(M)) INCREASE (DECREASE) (IN MILLIONS) Fuel and purchased power $(90.5) $(49.8) Nuclear operating costs 96.8 (16.5) Other operating costs 7.2 (8.9) ------ ------ TOTAL OPERATION AND MAINTENANCE EXPENSES 13.5 (75.2) Provision for depreciation and amortization (14.7) 73.0 General taxes (4.6) (27.7) Income taxes (35.4) (6.0) ------ ------ TOTAL OPERATING EXPENSES AND TAXES $(41.2) $(35.9) ====== ======
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 $7.3 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 decreased by $8.9 million in 2001 from the prior year, due to 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 $14.7 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 SFAS 142 TE's goodwill amortization in 2001 totaled $ 14.0 million. Depreciation and amortization increased by $73.0 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 $3.8 million in 2002 and $5.9 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 $264.1 million and $51.8 million, respectively, and will result in annualized savings of $23.2 million. 6 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 50% 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 $ 236 Working capital and other 45 (46) ----- ----- 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 50% 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. 7 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. 8 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. 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, 9 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 $578.2 million as of December 31, 2002 and $642.2 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 fall 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: 10
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 ------
Power Outage On August 14, 2003, eight states and southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. The cause of the outage has not been determined. Having restored service to its customers, FirstEnergy is now in the process of accumulating data and evaluating the status of its electrical system prior to and during the outage event. FirstEnergy is committed to working with the North American Electric Reliability Council and others involved to determine exactly what events in the entire affected region led to the outage. There is no timetable as to when this entire process will be completed. It is, however, expected to last several weeks, at a minimum. 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. 11 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 -- $578.2 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: - Net energy generated or purchased for retail load - Losses of energy over distribution lines - Allocations to distribution companies within the FirstEnergy system - Mix of kilowatt-hour usage by residential, commercial and industrial customers - 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 12 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. Ohio Transition Cost Amortization In developing TE's restructuring plan, the PUCO determined allowable transition costs based on amounts recorded on the EUOC's regulatory books. These costs exceeded those deferred or capitalized on TE's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). The Company uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for TE. In computing the transition cost amortization, TE includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 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 The regulations in the jurisdictions in which TE operates do not provide for recovery of goodwill. As a result, no amortization of goodwill has been recorded subsequent to the adoption of SFAS 142. 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 13 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 $504.5 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 $179.6 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). 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 beginning after June 15, 2003 (TE's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. 14 TE currently has transactions 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. TE currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. One of these entities TE 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 a 0.34 percent equity interest by Toledo Edison Capital Corp., a majority owned subsidiary. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and is effective at the beginning of the first interim period beginning after June 15, 2003 (FirstEnergy's third quarter of 2003) for all other financial instruments. TE did not enter into or modify any financial instruments within the scope of SFAS 150 during June 2003. Upon adoption of SFAS 150, effective July 1, 2003, TE expects to classify as debt the preferred stock of consolidated subsidiaries subject to mandatory redemptions with a carrying value of approximately $19 million as of June 30, 2003. Subsidiary preferred dividends on FirstEnergy's Consolidated Statements of Income are currently included in net interest charges. Therefore, the application of SFAS 150 will not require the reclassification of such preferred dividends to net interest charges. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence in a contract of a general index, such as the Consumer Price Index, would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. FirstEnergy is currently assessing the new guidance and has not yet determined the impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus will be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. FirstEnergy is currently assessing the new EITF consensus and has not yet determined the impact on its financial position or results of operations following adoption. 15 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (RESTATED*)
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------ (IN THOUSANDS) OPERATING REVENUES (a) (NOTE 1) .............. $ 996,045 $ 1,086,503 $ 954,947 ----------- ----------- ----------- OPERATING EXPENSES AND TAXES: Fuel and purchased power (Note 1) ......... 366,932 457,444 159,039 Nuclear operating costs (Note 1) .......... 252,608 155,832 172,363 Other operating costs (Note 1) ............ 141,997 134,744 157,686 ----------- ----------- ----------- Total operation and maintenance expenses 761,537 748,020 489,088 Provision for depreciation and amortization 162,082 176,796 106,514 General taxes ............................. 53,223 57,810 90,837 Income taxes .............................. (17,496) 17,913 74,183 ----------- ----------- ----------- Total operating expenses and taxes ..... 959,346 1,000,539 760,622 ----------- ----------- ----------- OPERATING INCOME ............................. 36,699 85,964 194,325 OTHER INCOME (NOTE 1) ........................ 13,329 15,652 8,669 ----------- ----------- ----------- INCOME BEFORE NET INTEREST CHARGES ........... 50,028 101,616 202,994 ----------- ----------- ----------- 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) (3,690) (1,519) ----------- ----------- ----------- Net interest charges ................... 55,170 58,925 64,850 ----------- ----------- ----------- NET INCOME (LOSS) ............................ (5,142) 42,691 138,144 PREFERRED STOCK DIVIDEND REQUIREMENTS .............................. 10,756 16,135 16,247 ----------- ----------- ----------- EARNINGS (LOSS) ON COMMON STOCK .............. $ (15,898) $ 26,556 $ 121,897 =========== =========== ===========
*See Note 1(M). (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. 16 THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (RESTATED*)
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 1,309 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 ----------- ----------- 129,462 125,433 ----------- ----------- DEFERRED CHARGES: Regulatory assets .......................................... 578,243 642,246 Goodwill ................................................... 504,522 504,522 Property taxes ............................................. 23,429 23,836 Other ...................................................... 14,257 1,909 ----------- ----------- 1,120,451 1,172,513 ----------- ----------- $ 2,861,614 $ 2,875,908 =========== =========== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity ................................ $ 681,195 $ 629,805 Preferred stock not subject to mandatory redemption ........ 126,000 126,000 Long-term debt ............................................. 557,265 646,174 ----------- ----------- 1,364,460 1,401,979 ----------- ----------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock ....... 189,355 347,593 Accounts payable- Associated companies .................................... 171,862 53,960 Other ................................................... 9,338 29,818 Notes payable to associated companies ...................... 149,653 17,208 Accrued taxes ............................................. 34,676 35,355 Accrued interest ........................................... 16,377 19,918 Deferred lease costs ....................................... 24,600 24,600 Other ...................................................... 57,462 41,622 ----------- ----------- 653,323 570,074 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes .......................... 158,279 170,364 Accumulated deferred investment tax credits ................ 29,255 31,266 Nuclear plant decommissioning costs ........................ 179,587 151,226 Pensions and other postretirement benefits ................. 82,553 120,561 Deferred lease costs ....................................... 317,200 341,800 Other ...................................................... 76,957 88,638 ----------- ----------- 843,831 903,855 COMMITMENTS AND CONTINGENCIES ----------- ----------- (Notes 2 and 5) ............................................ $ 2,861,614 $ 2,875,908 =========== ===========
*See Note 1(M). The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. 17 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (RESTATED*)
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)................................................... (20,012) 7,100 Retained earnings (Note 3A)...................................................................... 76,978 98,476 ---------- ---------- Total common stockholder's equity............................................................. 681,195 629,805 ========== ========== 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 ---------- ----------
*See Note 1(M). 18 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (RESTATED*) (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................................................................................ $1,364,460 $1,401,979 ========== ==========
* See Note 1(M). ** 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. 19 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 ------------- --------- ----- ------- ------------- -------- RESTATED RESTATED (SEE NOTE 1(M)) (SEE NOTE 1(M)) (DOLLARS IN THOUSANDS) Balance, January 1, 2000............... 39,133,887 $ 195,670 $ 328,559 $ -- $ 27,475 Cumulative effect for restatement (see Note 1 (m)................... 4,349 - --------------------------------------------------------------------------------------------------------------------------------- Restated balance at January 1, 2000.... 31,824 Net income.......................... $ 138,144 138,144 ========== 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 86,618 Unrealized gain on investments, net of $00 of Net income.......................... $ 42,691 42,691 Unrealized gain on investments, net of $4,800 of income taxes......... 7,100 7,100 ---------- Comprehensive income................ $ 49,791 ========== 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 7,100 98,476 Net income (loss)................... $ ( 5,142) (5,142) Unrealized loss on investments, net of $(4,034)of income taxes........ (5,997) (5,997) Minimum liability for unfunded retirement benefits, net of $(15,042,000) of income taxes..... (21,115) (21,115) ---------- Comprehensive loss.................. $ (32,254) Equity contribution from parent..... 100,000 Cash dividends on preferred stock... (9,457) Cash dividends on common stock...... (5,600) Preferred stock redemption premiums. (1,299) - --------------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002............. 39,133,887 $ 195,670 $ 428,559 $ (20,012) $ 76,978 =================================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
NOT SUBJECT TO MANDATORY REDEMPTION ---------------------------- NUMBER 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 ============================================================================
* See Note 1(M) to the Consolidated Financial Statements. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 20 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (RESTATED*)
FOR THE YEARS ENDED DECEMBER 31, 2002 2001 2000 - ------------------------------------------------------------------------------------------------ (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (Loss) .................................. $ (5,142) $ 42,691 $ 138,144 Adjustments to reconcile net income (loss) to net cash from operating activities: Provision for depreciation and amortization .. 162,082 176,796 106,514 Nuclear fuel and lease amortization .......... 11,866 22,222 23,881 Deferred income taxes, net ................... (24,821) (1,383) 22,165 Investment tax credits, net .................. (1,851) (3,832) (1,827) Receivables .................................. 5,164 (1,437) (6,671) Materials and supplies ....................... (5,582) 8,336 4,093 Accounts payable ............................. 40,801 22,144 13,997 Accrued taxes ................................ (4,881) (17,671) (223) Accrued interest ............................. (3,541) (28) (2,015) Prepayments and other ........................ 11,125 12,571 (1,220) Deferred lease costs ......................... (24,600) (24,600) (5,700) Other ........................................ (5,082) (45,953) (33,322) --------- --------- --------- Net cash used for 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 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 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 ========= ========= =========
*See Note 1(M). The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 21 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF TAXES (RESTATED*)
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 ............................................. $ 12,845 $ 22,244 $ 56,631 State ............................................... 3,983 4,840 1,811 --------- --------- --------- 16,828 27,084 58,442 --------- --------- --------- Deferred, net- Federal ............................................. (19,091) 4,725 22,216 State ............................................... (5,570) (1,539) (51) --------- --------- --------- (24,661) 3,186 22,165 --------- --------- --------- Investment tax credit amortization ..................... (2,011) (3,908) (1,827) --------- --------- --------- Total provision for income taxes .............. $ (9,844) $ 26,362 $ 78,780 ========= ========= ========= INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating income ....................................... $ (17,496) $ 17,913 $ 74,183 Other income ........................................... 7,652 8,449 4,597 --------- --------- --------- Total provision for income taxes .............. $ (9,844) $ 26,362 $ 78,780 ========= ========= ========= RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income (loss) before provision for income taxes ... $ (14,986) $ 69,053 $ 216,924 ========= ========= ========= Federal income tax expense at statutory rate ........... $ (5,245) $ 24,169 $ 75,923 Increases (reductions) in taxes resulting from- State income taxes, net of federal income tax benefit (1,031) 2,146 1,144 Amortization of investment tax credits .............. (2,011) (3,908) (1,827) Amortization of tax regulatory assets ............... (2,362) (2,563) (1,737) Amortization of goodwill ............................ -- 4,911 4,894 Other, net ............................................. 805 1,607 383 --------- --------- --------- Total provision for income taxes .............. $ (9,844) $ 26,362 $ 78,780 ========= ========= ========= ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Property basis differences ............................. $ 177,262 $ 171,976 $ 163,537 Competitive transition charge .......................... 196,812 239,088 192,444 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 ............................. (14,276) 4,800 -- Above market leases .................................... (140,399) (150,634) (160,868) Retirement benefits .................................... (9,768) (35,126) (28,656) Other .................................................. (54,124) (63,861) (2,334) --------- --------- --------- Net deferred income tax liability ................... $ 158,279 $ 170,364 $ 157,674 ========= ========= =========
* See Note 1(M). ** 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. 22 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. 23 (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 (see Note 1(M)) 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. See Note 1(M) for further discussion of the Ohio transition plan. (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 in connection with the purchase accounting and impairment tests prepared in connection with the transition plan), 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 24 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 $179.6 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 will be a $115 million increase to income ($67 million net of tax). 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 $14 million of goodwill annually. The goodwill balance as of December 31, 2002 and 2001 was $505 million. The following table shows what net income would have been if goodwill amortization had been excluded from prior periods:
2002 2001 2000 -------- -------- -------- RESTATED RESTATED RESTATED (IN THOUSANDS) Reported net income (loss) .... $ (5,142) $ 42,691 $138,114 Add back goodwill amortization -- 14,032 13,984 -------- -------- -------- Adjusted net income (loss) .... $ (5,142) $ 56,723 $152,098 ======== ======== ========
(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: 25
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. 26 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 .. $ 18.7 $ 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%
27 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 28 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 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. 29 Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:
2002 2001 -------- -------- REVISED (SEE NOTE 1(M)) (IN MILLIONS) Regulatory transition costs $ 582.1 $ 648.1 Loss on reacquired debt ... 3.0 3.2 Other ..................... (6.9) (9.1) -------- -------- Total .............. $ 578.2 $ 642.2 ======== ========
(M) RESTATEMENTS- The Company is restating its financial statements for the three years ended December 31, 2002. The primary modifications include revisions to reflect a change in the method of amortizing costs being recovered through the Ohio transition plan and recognition of above-market values of certain leased generation facilities. In addition, certain other immaterial previously unrecorded adjustments are now reflected in results for the three years ended December 31, 2002. Transition Cost Amortization - The Company amortizes transition costs, described in Note 1(C) above, using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements, but not in the financial statements prepared under GAAP. TE has revised the amortization schedule under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets the first several years of the transition cost recovery period, compared with the method previously applied. The change in method results in no change in total amortization of the previously recorded regulatory assets recovered under the transition period through the end of 2007. Above-Market Lease Costs - In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior. The merger was accounted for as an acquisition of Centerior, the parent company of TE, under the purchase accounting rules of APB 16. In connection with the reassessment of the accounting for the transition plan, the FirstEnergy reassessed its accounting for the Centerior purchase and determined that above-market lease liabilities should have been recorded at the time of the merger. Accordingly, the Company has restated its financial statements to record additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which TE had previously entered into sale-leaseback arrangements. The Company recorded an increase in goodwill related to the above-market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional consideration would have increased goodwill at the date of the merger. The corresponding impact of the above-market lease liability for the Bruce Mansfield Plant was recorded as a regulatory asset because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided under the Company, Regulatory Plan in effect at the time of the merger and subsequently under the transition plan. The total above-market lease obligation of $111 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017 (approximately $5.7 million annually). The additional goodwill has been recorded effective as of the merger date, and amortization has been recorded through 2001, when goodwill amortization ceased with the adoption of SFAS 142. The total above-market lease obligation of $298 million associated with the Bruce Mansfield Plant is being amortized through the end of 2016 (approximately $18.9 million annually). Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation resulting in no impact to net income. Beginning in 2001, the unamortized regulatory asset has been included in the Company's revised amortization schedule for regulatory assets and amortized through the end of the recovery period in 2007. 30 The Company has reflected the impact of the accounting for the above market lease obligations for the period from the merger in 1997 through 1999 as a cumulative effect adjustment of $4.3 million to retained earnings as of January 1, 2000. The after-tax effect of these items in the years ended December 31, 2002, 2001 and 2000 was as follows:
INCOME STATEMENT EFFECTS INCREASE (DECREASE) TRANSITION REVERSAL COST OF LEASE AMORTIZATION OBLIGATIONS(1) TOTAL ------------ -------------- ----- (IN THOUSANDS) Year ended December 31, 2002 Nuclear operating expenses $ -- $ (5,700) $ (5,700) Other operating expenses -- (18,900) (18,900) Provision for depreciation and amortization 28,400 40,200 68,600 Income taxes (12,559) (6,372) (18,931) -------- -------- -------- Total expense $ 15,841 $ 9,228 $ 25,069 ======== ======== ======== Net income effect $(15,841) $ (9,228) $(25,069) ======== ======== ======== Year ended December 31, 2001 Nuclear operating expenses $ -- $ (5,700) $ (5,700) Other operating expenses -- (18,900) (18,900) Provision for depreciation and amortization 13,600 33,000 46,600 Income taxes (5,619) (3,177) (8,796) -------- -------- -------- Total expense $ 7,981 $ 5,223 $ 13,204 ======== ======== ======== Net income effect $ (7,981) $ (5,223) $(13,204) ======== ======== ======== Year ended December 31, 2000 Nuclear operating expenses $ -- $ (5,700) $ (5,700) Other operating expenses -- -- -- Provision for depreciation and amortization -- 1,600 1,600 Income taxes -- 2,371 2,371 -------- -------- -------- Total expense $ -- $ (1,729) $ (1,729) ======== ======== ======== Net income effect $ -- $ 1,729 $ 1,729 ======== ======== ========
(1) The provision for depreciation and amortization in 2001 and 2000 includes goodwill amortization of $1.6 million. In addition, the impact of the above market lease obligations increased the following balances in the consolidated balance sheet as of January 1, 2000: (in thousands) Goodwill $ 61,990 Regulatory assets 298,000 --------- Total assets $ 359,990 ========= Other current liabilities $ 24,600 Deferred income taxes (41,059) Other deferred credits 372,100 --------- Total liabilities $ 355,641 ========= Retained earnings $ 4,349 =========
31 The net impact of the adjustments described above for the next five years is expected to reduce net income in 2003 through 2005 and increase net income in 2006 through 2007. After giving effect to the restatement, total transition cost amortization (including above market leases) is expected to approximate the following for the years from 2003 through 2007 (in millions).
2003 $53 2004 71 2005 99 2006 76 2007 75
Other Unrecorded Adjustments This restatement for the years ended December 31, 2002, 2001 and 2000 also includes adjustments that were not previously recognized that principally related to an adjustment to unbilled revenue in 2001 with a corresponding impact in 2002. The net income impact by year was $7.2 million in 2002, $(7.0) million in 2001 and $(0.8) million in 2000. The effects of all of the changes in this restatement on the previously reported Consolidated Balance Sheet as of December 31, 2002 and 2001, and the Consolidated Statements of Income and Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000 are as follows:
2002 2001 2000 -------------------------- -------------------------- ------------------------- AS PREVIOUSLY AS AS PREVIOUSLY AS AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED ------------- ---------- ------------- ---------- ------------- ---------- (IN THOUSANDS) CONSOLIDATED STATEMENTS OF INCOME OPERATING REVENUES: $ 987,645 $ 996,045 $1,094,903 $1,086,503 $ 954,947 $ 954,947 EXPENSES: Fuel and purchased power 366,932 366,932 457,444 457,444 159,039 159,039 Nuclear operating costs 258,308 252,608 161,532 155,832 178,063 172,363 Other operating costs 163,267 141,997 151,244 134,744 156,286 157,686 ---------- ---------- ---------- ---------- ---------- ---------- Total operation and maintenance expenses 788,507 761,537 770,220 748,020 493,388 489,088 Provision for depreciation and amortization 93,482 162,082 130,196 176,796 104,914 106,514 General taxes 53,223 53,223 57,810 57,810 90,837 90,837 Income taxes (2,745) (17,496) 31,193 17,913 72,394 74,183 ---------- ---------- ---------- ---------- ---------- ---------- Total expenses 932,467 959,346 989,419 1,000,539 761,533 760,622 ---------- ---------- ---------- ---------- ---------- ---------- OPERATING INCOME 55,178 36,699 105,484 85,964 193,414 194,325 OTHER INCOME 13,329 13,329 15,652 15,652 8,669 8,669 ---------- ---------- ---------- ---------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES 68,507 50,028 121,136 101,616 202,083 202,994 ---------- ---------- ---------- ---------- ---------- ---------- NET INTEREST CHARGES 55,170 55,170 58,225 58,925 64,850 64,850 ---------- ---------- ---------- ---------- ---------- ---------- NET INCOME (LOSS) 13,337 (5,142) 62,911 42,691 137,233 138,144 PREFERRED STOCK DIVIDEND REQUIREMENT 11,356 10,756 16,135 16,135 16,247 16,247 ---------- ---------- ---------- ---------- ---------- ---------- EARNINGS (LOSS) ON COMMON STOCK $ 1,981 $ (15,898) $ 46,776 $ 26,556 $ 120,986 $ 121,897 ========== ========== ========== ========== ========== ==========
32
2002 2001 2000 -------------------------------------------------------------------------------- AS AS AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED -------------------------------------------------------------------------------- (IN THOUSANDS) CONSOLIDATED BALANCE SHEETS ASSETS CURRENT ASSETS $ 129,462 $ 129,462 $ 133,833 $ 125,433 PROPERTY, PLANT AND EQUIPMENT 1,031,829 1,031,829 993,152 993,152 INVESTMENTS 579,872 579,872 584,810 584,810 DEFERRED CHARGES: Regulatory assets 392,643 578,243 388,846 642,246 Goodwill 445,732 504,522 445,732 504,522 Other 37,686 37,686 25,745 25,745 ---------- ---------- ---------- ---------- 876,061 1,120,451 860,323 1,172,513 ---------- ---------- ---------- ---------- $2,617,224 $2,861,614 $2,572,118 $2,875,908 ========== ========== ========== ========== LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES $ 628,084 $ 681,195 $ 546,167 $ 570,074 CAPITALIZATION Common stockholders' equity 712,931 682,995 637,665 629,805 Preferred stock not subject to mandatory redemption 126,000 126,000 126,000 126,000 Long-term debt 557,265 557,265 646,174 646,174 ---------- ---------- ---------- ---------- 1,396,196 1,364,460 1,409,839 1,401,979 ---------- ---------- ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes 223,087 158,279 213,145 170,364 Accumulated deferred investment tax credits 29,491 29,255 31,342 31,266 Nuclear plant decommissioning costs 180,856 179,587 162,426 151,226 Other 159,510 476,710 209,199 550,999 ---------- ---------- ---------- ---------- 592,944 843,831 616,112 903,855 ---------- ---------- ---------- ---------- $2,617,224 $2,861,614 $2,572,118 $2,875,908 ========== ========== ========== ========== CONSOLIDATED STATEMENTS OF CASH FLOWS CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 13,337 $ (5,142) $ 62,911 $ 42,691 $ 137,233 $ 138,144 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization 93,482 162,082 130,196 176,796 104,914 106,514 Nuclear fuel and lease amortization 11,866 11,866 22,222 22,222 23,881 23,881 Deferred income taxes, net (5,868) (24,821) 11,897 (1,383) 20,376 22,165 Investment tax credits, net (1,851) (1,851) (3,832) (3,832) (1,827) (1,827) Receivables 13,564 5,164 (9,837) (1,437) (6,671) (6,671) Materials and supplies (5,582) (5,582) 8,336 8,336 4,093 4,093 Accounts payable 42,501 40,801 19,744 22,144 13,997 13,997 Deferred rents and sale/leaseback -- (24,600) -- (24,600) -- (5,700) Other (5,911) (2,379) (51,781) (51,081) (38,180) (36,780) ---------- ---------- ---------- ---------- ---------- ---------- Net cash provided from operating activities $ 155,538 $ 155,538 $ 188,856 $ 189,856 $ 257,816 $ 257,816 ========== ========== ========== ========== ========== ========== CASH FLOWS FROM FINANCING ACTIVITIES $ (29,299) $ (29,299) $ (97,828) $ (97,828) $ (179,515) $ (179,515) ========== ========== ========== ========== ========== ========== CASH FLOWS FROM INVESTING ACTIVITIES $ (105,853) $ (105,853) $ (93,111) $ (93,111) $ 77,228 $ (77,228) ========== ========== ========== ========== ========== ==========
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. 33 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. 34 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. 35 (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 and unrealized losses of $(5,997). 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. 36 (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. 37 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. 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 38 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 (TE's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. TE currently has transactions 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. TE currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. One of these entities TE 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 a 0.34 percent equity interest by Toledo Edison Capital Corp., a majority owned subsidiary. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and is effective at the beginning of the first interim period beginning after June 15, 2003 (TE's third quarter of 2003) for all other financial instruments. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence in a contract of a general index, such as the Consumer Price Index, would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. FirstEnergy is currently assessing the new guidance and has not yet determined the impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus will be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. TE is currently assessing the new EITF consensus and has not yet determined the impact on its financial position or results of operations following adoption. 39 8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
THREE MONTHS ENDED MARCH 31, 2002(a) JUNE 30, 2002(a) SEPTEMBER 30, 2002(a) DECEMBER 31, 2002(a) - -------------------------------------------------------------------------------------------------------------------------------- AS AS AS AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED -------- -------- -------- -------- -------- -------- -------- -------- (IN MILLIONS) Operating Revenues $ 244.1 $ 252.6 $ 250.3 $ 250.3 $ 269.9 $ 269.9 $ 223.3 $ 223.3 Operating Expenses and Taxes 234.5 241.9 216.2 222.7 244.8 251.7 236.9 243.1 Operating Income (Loss) 9.6 10.7 34.1 27.6 25.1 18.2 (13.6) (19.8) - -------------------------------------------------------------------------------------------------------------------------------- Other Income 4.4 4.3 3.7 3.7 4.0 4.0 1.1 1.2 Net Interest Charges 14.7 14.7 14.8 14.9 14.5 14.5 11.2 11.1 Net Income (Loss) $ (0.7) $ 0.3 $ 23.0 $ 16.5 $ 14.6 $ 7.7 $ (23.7) $ (29.7) - -------------------------------------------------------------------------------------------------------------------------------- Earnings (Loss) Applicable to Common Stock $ (5.4) $ (4.4) $ 20.8 $ 14.3 $ 12.4 $ 5.5 $ (25.8) $ (31.4) ================================================================================================================================
THREE MONTHS ENDED MARCH 31, 2001(a) JUNE 30, 2001(a) SEPTEMBER 30, 2001(a) DECEMBER 31, 2001(a) - ---------------------------------------------------------------------------------------------------------------------------- AS AS AS AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS PREVIOUSLY AS REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED REPORTED RESTATED -------- -------- -------- -------- -------- -------- -------- -------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Operating Revenues $ 271.6 $ 271.6 $ 263.0 $ 263.0 $ 306.5 $ 306.5 $ 253.8 $ 245.4 Operating Expenses and Taxes 243.3 246.6 229.6 232.9 278.9 282.2 237.6 238.8 Operating Income 28.3 25.0 33.4 30.1 27.6 24.3 16.2 6.6 Other Income 3.8 3.8 2.2 2.2 3.9 3.9 5.7 5.7 - ---------------------------------------------------------------------------------------------------------------------------- Net Interest Charges 15.9 15.9 12.6 12.6 15.1 15.1 14.6 15.3 Net Income (Loss) $ 16.2 $ 12.9 $ 23.0 $ 19.7 $ 16.4 $ 13.1 $ 7.3 $ (3.0) - ---------------------------------------------------------------------------------------------------------------------------- Earnings on common Stock $ 12.2 $ 8.9 $ 18.9 $ 15.6 $ 12.4 $ 9.1 $ 3.3 $ (7.0) ============================================================================================================================
(a) See Note 1(M) for discussion of restated financial data. The changes are principally based on the impact of the revised transition cost amortization and above market rates. In addition, the other adjustments discussed in Note 1(M) increased (decreased) net income for the quarterly periods as follows: (in millions)
2002 2001 ---- ---- March 31 6.9 -- December 31 0.3 (7.0)
40 REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors of The Toledo Edison Company: In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of The Toledo Edison Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiary as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 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. As discussed in Note 1(D) to the consolidated financial statements, the Company changed its method of accounting for goodwill in 2002. As discussed in Note 1(M) to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements as of December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002. PricewaterhouseCoopers LLP Cleveland, Ohio August 18, 2003 41 -----END PRIVACY-ENHANCED MESSAGE-----