10-Q 1 main.txt FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _______________ Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. ----------- ------------------------------------- ------------------ 333-21011 FIRSTENERGY CORP. 34-1843785 (An Ohio Corporation) 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-2578 OHIO EDISON COMPANY 34-0437786 (An Ohio Corporation) 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 34-0150020 (An Ohio Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3583 THE TOLEDO EDISON COMPANY 34-4375005 (An Ohio Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3491 PENNSYLVANIA POWER COMPANY 25-0718810 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3141 JERSEY CENTRAL POWER & LIGHT COMPANY 21-0485010 (A New Jersey Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-446 METROPOLITAN EDISON COMPANY 23-0870160 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3522 PENNSYLVANIA ELECTRIC COMPANY 25-0718085 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 Indicate by check mark whether each of the registrants (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 the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: OUTSTANDING CLASS AS OF NOVEMBER 13, 2002 ----- ----------------------- FirstEnergy Corp., $.10 par value 297,636,276 Ohio Edison Company, no par value 100 The Cleveland Electric Illuminating Company, no par value 79,590,689 The Toledo Edison Company, $5 par value 39,133,887 Pennsylvania Power Company, $30 par value 6,290,000 Jersey Central Power & Light Company, $10 par value 15,371,270 Metropolitan Edison Company, no par value 859,500 Pennsylvania Electric Company, $20 par value 5,290,596 FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company common stock; Ohio Edison Company is the sole holder of Pennsylvania Power Company common stock. This combined Form 10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy. This Form 10-Q 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, legislative and regulatory changes (including revised environmental requirements), the availability and cost of capital, ability to accomplish or realize anticipated benefits from strategic initiatives and other similar factors. TABLE OF CONTENTS Pages Part I. Financial Information Notes to Financial Statements................................ 1-11 FirstEnergy Corp. Consolidated Statements of Income............................ 12 Consolidated Balance Sheets.................................. 13-14 Consolidated Statements of Cash Flows........................ 15 Report of Independent Accountants............................ 16 Management's Discussion and Analysis of Results of Operations and Financial Condition........................... 17-30 Ohio Edison Company Consolidated Statements of Income............................ 31 Consolidated Balance Sheets.................................. 32-33 Consolidated Statements of Cash Flows........................ 34 Report of Independent Accountants............................ 35 Management's Discussion and Analysis of Results of Operations and Financial Condition......................... 36-40 The Cleveland Electric Illuminating Company Consolidated Statements of Income............................ 41 Consolidated Balance Sheets.................................. 42-43 Consolidated Statements of Cash Flows........................ 44 Report of Independent Accountants............................ 45 Management's Discussion and Analysis of Results of Operations and Financial Condition......................... 46-50 The Toledo Edison Company Consolidated Statements of Income............................ 51 Consolidated Balance Sheets.................................. 52-53 Consolidated Statements of Cash Flows........................ 54 Report of Independent Accountants............................ 55 Management's Discussion and Analysis of Results of Operations and Financial Condition......................... 56-60 Pennsylvania Power Company Statements of Income......................................... 61 Balance Sheets............................................... 62-63 Statements of Cash Flows..................................... 64 Report of Independent Accountants............................ 65 Management's Discussion and Analysis of Results of Operations and Financial Condition......................... 66-69 Jersey Central Power & Light Company Consolidated Statements of Income............................ 70 Consolidated Balance Sheets.................................. 71-72 Consolidated Statements of Cash Flows........................ 73 Report of Independent Accountants............................ 74 Management's Discussion and Analysis of Results of Operations and Financial Condition......................... 75-80 TABLE OF CONTENTS (Cont'd) Pages Metropolitan Edison Company Consolidated Statements of Income............................ 81 Consolidated Balance Sheets.................................. 82-83 Consolidated Statements of Cash Flows........................ 84 Report of Independent Accountants............................ 85 Management's Discussion and Analysis of Results of Operations and Financial Condition......................... 86-91 Pennsylvania Electric Company Consolidated Statements of Income............................ 92 Consolidated Balance Sheets.................................. 93-94 Consolidated Statements of Cash Flows........................ 95 Report of Independent Accountants............................ 96 Management's Discussion and Analysis of Results of Operations and Financial Condition......................... 97-102 Controls and Procedures...................................... 103 Part II. Other Information PART I. FINANCIAL INFORMATION ------------------------------ FIRSTENERGY CORP. AND SUBSIDIARIES OHIO EDISON COMPANY AND SUBSIDIARIES THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES THE TOLEDO EDISON COMPANY AND SUBSIDIARY PENNSYLVANIA POWER COMPANY JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES METROPOLITAN EDISON COMPANY AND SUBSIDIARIES PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (Unaudited) 1 - FINANCIAL STATEMENTS: The principal business of FirstEnergy Corp. (FirstEnergy) is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE), Pennsylvania Power Company (Penn), American Transmission Systems, Inc. (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." Penn is a wholly owned subsidiary of OE. FirstEnergy's results include the results of JCP&L, Met-Ed and Penelec from the November 7, 2001 merger date with GPU, Inc., the former parent company of JCP&L, Met-Ed and Penelec. The merger was accounted for by the purchase method of accounting and the applicable effects were reflected on the financial statements of JCP&L, Met-Ed and Penelec as of the merger date. Accordingly, the post-merger financial statements reflect a new basis of accounting, and pre-merger period and post-merger period financial results of JCP&L, Met-Ed and Penelec (separated by a heavy black line) are presented. FirstEnergy's consolidated financial statements also include its other principal subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FEFSG); MYR Group, Inc. (MYR); 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. FEFSG 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. The condensed unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2001 for FirstEnergy and the Companies. Significant intercompany transactions have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from those estimates. The reported results of operations are not indicative of results of operations for any future period. Certain prior year amounts have been reclassified to conform with the current year presentation. Preferred Securities The sole assets of the CEI subsidiary trust that is the obligor on the preferred securities included in FirstEnergy's and CEI's capitalization are $103,093,000 principal amount of 9% Junior Subordinated Debentures of CEI due December 31, 2006. Met-Ed and Penelec have each formed statutory business trusts for the issuance of $100 million each of preferred securities due 2039. 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, the sole assets and sources of revenues of each trust are the preferred securities of the applicable limited partnership, whose sole assets are in the 7.35% and 7.34% subordinated debentures (aggregate principal amount of $103.1 million each) 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. 1 Securitized Transition Bonds On June 11, 2002, JCP&L Transition Funding LLC (the 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 or did not purchase any of the transition bonds, which are included in long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheet. The transition bonds represent obligations only of the Issuer and are collateralized solely by the equity and assets of the Issuer, which consist primarily of bondable transition property. The bondable transition property is solely the property of the Issuer. Bondable transition property is a presently existing property right which includes the right to charge, collect and receive from JCP&L's utility 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. Derivative Accounting 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. 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. The current net deferred loss of $116.7 million included in Accumulated Other Comprehensive Loss (AOCL) as of September 30, 2002, for derivative hedging activity as compared to the June 30, 2002 balance of $133.0 million in AOCL, resulted from $13.2 million of gains related to current hedging activity and $3.1 million of net hedge losses included in earnings during the quarter. Approximately $17.8 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 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. 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 September 30, 2002, FirstEnergy's AOCL was approximately $118.7 million as compared to the December 31, 2001 balance of $169.0 million. The 2002 year-to-date change is shown in the following table: For the Nine Months Ended Sept. 30, 2002 -------------------- (In thousands) Net income...................................... $660,058 Other comprehensive income (loss), net of tax: Derivative hedge transactions................. 52,752 All other..................................... (2,479) -------- Comprehensive income............................ $710,331 ======== 2 2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES: Capital Expenditures FirstEnergy's current forecast reflects expenditures of approximately $3.2 billion (OE-$250 million, CEI-$353 million, TE-$209 million, Penn-$89 million, JCP&L-$541 million, Met-Ed-$309 million, Penelec-$355 million, ATSI-$126 million, FES-$760 million and other subsidiaries-$257 million) for property additions and improvements from 2002-2006, of which approximately $920 million (OE-$78 million, CEI-$130 million, TE-$88 million, Penn-$40 million, JCP&L-$113 million, Met-Ed-$52 million, Penelec-$52 million, ATSI-$28 million, FES-$186 million and other subsidiaries-$153 million) is applicable to 2002. Investments for additional nuclear fuel during the 2002-2006 period are estimated to be approximately $516 million (OE-$49 million, CEI-$41 million, TE-$24 million, Penn-$31 million and FES-$371 million), of which approximately $54 million (OE-$16 million, CEI-$17 million, TE-$11 million and Penn-$10 million) applies to 2002. 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 ratings contingent collateralization provisions. As of September 30, 2002, outstanding guarantees and other assurances aggregated $880.9 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 assets of FirstEnergy. The likelihood that such parental guarantees of $831.8 million as of September 30, 2002 will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related activities is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $25.8 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. Requirements of 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 September 30, 2002, rating-contingent collateralization totaled $23.3 million. FirstEnergy monitors these collateralization provisions and updates its total exposure monthly. 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 $235 million, which is included in the construction forecast provided under "Capital Expenditures" for 2002 through 2006. 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 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 3 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 which are currently scheduled for hearings in February 2003. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of these proceedings, FirstEnergy believes the Sammis Plant is in full compliance with the Clean Air Act and the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. The Companies have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of September 30, 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 a non-bypassable societal benefits charge. The Companies have total accrued liabilities aggregating approximately $57.9 million (JCP&L-$50.7 million, CEI-$2.8 million, TE-$0.2 million, Met-Ed-$0.2 million, Penelec-0.4 million and other-$3.6 million) as of September 30, 2002. FirstEnergy does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Other Commitments and Contingencies GPU made significant investments in foreign businesses and facilities through its GPU Power subsidiary. Although FirstEnergy attempts 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 $270 million as of September 30, 2002. The lenders include the Overseas Private Investment Corporation, US Export Import Bank and a commercial bank syndicate. FirstEnergy has also 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. 4 3 - PENDING DIVESTITURES: 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 Accounting Principles Board Opinion (APB) No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," with physically and operationally separable activities. Application of Emerging Issues Task Force (EITF) Issue No. 87-11, "Allocation of Purchase Price to Assets to Be Sold," required that expected, pre-sale cash flows, including incremental interest costs on related acquisition debt, of these operations be considered part of the purchase price allocation. Accordingly, subsequent to the merger date, results of operations and incremental interest costs related to these international subsidiaries were not included in FirstEnergy's Consolidated Statements of Income. Additionally, assets and liabilities of these international operations were segregated under separate captions in the Consolidated Balance Sheet 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, FirstEnergy's wholly owned holding company of 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 interest in Avon for approximately $1.9 billion (including the assumption of $1.7 billion of debt). FirstEnergy 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) from Aquila for its 79.9 percent interest. As of May 8, 2002, Avon had approximately $380 million in cash and cash equivalents. FirstEnergy and Aquila together own all of the outstanding shares of Avon through a jointly owned subsidiary, with each company having a 50-percent voting interest. Originally, in accordance with applicable accounting guidance, the earnings of those foreign operations were not recognized in current earnings from the date of the GPU acquisition until February 6, 2002. However, the revision to the initial offer by Aquila caused a reversal of this accounting in the first quarter of 2002, resulting in the recognition of a cumulative effect of a change in accounting which increased net income by $31.7 million. This resulted from the application of guidance provided by EITF Issue No. 90-6, "Accounting for Certain Events Not Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to Be Sold," accounting under EITF Issue No. 87-11, recognizing the net income of Avon from November 7, 2001 to February 6, 2002 that previously was not recognized by FirstEnergy in its consolidated earnings as discussed above. 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. Based on its assessment of the probability of sale and several other key assumptions such as pricing, growth of customer base and the timing of an economic recovery, FirstEnergy has determined that it is not probable that the current economic conditions in Argentina have eroded the fair value recorded for Emdersa; as a result, an impairment writedown of this investment is not warranted as of September 30, 2002. FirstEnergy will continue to assess the potential impact of these and other related events on the realizability of the value recorded for Emdersa. FirstEnergy continues to pursue divesting Emdersa and, in accordance with EITF Issue No. 87-11, has classified its assets and liabilities in the Consolidated Balance Sheet as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale". Potential investors recently retained a financial advisor to assist in the due diligence process and FirstEnergy believes it is probable that preliminary negotiations with those investors will be completed in 2002. If FirstEnergy has not completed the sale of all of its interest in Emdersa or has not reached a definitive agreement in 2002 to sell such interest, those assets would no longer be classified as "Assets Pending Sale" on FirstEnergy's Consolidated Balance Sheet and Emdersa's results of operations would be included on FirstEnergy's Consolidated Statement of Income. In addition, Emdersa's cumulative results of operations (from November 7, 2001 through the date that it would become probable that a definitive sale agreement for all of FirstEnergy's interest would not be reached in 2002) would be reflected on FirstEnergy's Consolidated Statement of Income as a "Cumulative Effect of a Change in Accounting" under EITF 90-6. As of September 30, 2002, that adjustment would have reduced FirstEnergy's net income by approximately $94 million ($0.32 per share of common stock). Other international operations are being considered for sale; however, as of the merger date those sales were not judged to be probable of occurring in 2002. 5 The following table shows the net changes in "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale" from December 31, 2001 to September 30, 2002:
Dec. 31, Year-to-Date Sept. 30, 2001 Changes 2002 -------- ------------ --------- (In millions) Assets Pending Sale: Current assets................................ $ 595 $ (574) $ 21 Property, plant and equipment................. 1,915 (1,838) 77 Investments................................... 142 (142) -- Deferred charges.............................. 766 (614) 152 ------ ------- ---- Total....................................... 3,418 (3,168) 250 Liabilities Related to Assets Pending Sale: Current liabilities........................... 1,055 (953) 102 Long-term debt................................ 1,432 (1,432) -- Deferred credits.............................. 468 ( 464) 4 ------ ------- ---- Total....................................... 2,955 (2,849) 106 Net Assets Pending Sale....................... $ 463 $ (319) $144 ====== ======= ====
The September 30, 2002 balance represents the assets and liabilities of the Argentina operations, Emdersa. The year-to-date change is primarily the result of the sale of Avon. Sale of Generating Assets In November 2001, FirstEnergy had 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 is reserving 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. FirstEnergy is pursuing opportunities with other parties who have expressed interest in purchasing the plants. FirstEnergy expects to conclude a bid process in the fourth quarter of 2002, with the objective of executing a sales agreement by year-end if a bid is deemed acceptable. Any net after-tax gain from such sale, based on the difference between the sale price of the plants and their market price used in the Ohio restructuring transition plan, will be credited to customers by reducing the transition cost recovery period. If FirstEnergy has not executed a sales agreement by year-end, it would need to reflect up to $58 million of previously unrecognized depreciation and other transaction costs for these plants from November 2001 through September 2002 on its Consolidated Statement of Income. 4 - REGULATORY MATTERS: In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included the following provisions which are reflected in the Companies' respective state regulatory plans: o allowing the Companies' electric customers to select their generation suppliers; o establishing provider of last resort (PLR) obligations to non-shopping customers in the Companies' service areas; o allowing recovery of potentially stranded investment (or transition costs); o itemizing (unbundling) the current price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; o deregulating the Companies' electric generation businesses; and o continuing regulation of the Companies' transmission and distribution systems. Ohio FirstEnergy's transition plan (which it filed on behalf of OE, CEI and TE (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 FirstEnergy's 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 6 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. 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). Based on actual shopping levels through October 2002, FirstEnergy has achieved all of its required 20% customer shopping goals and there is no longer risk of 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 New Jersey Board of Public Utilities (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 transition bonds through a new wholly owned subsidiary, JCP&L Transition Funding LLC, in May 2002, which is 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 September 30, 2002, the accumulated deferred cost balance totaled approximately $482 million. The Final Order 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. Rate filing hearings are anticipated in the first quarter of 2003. The NJBPU has directed the Office of Administrative Law to provide an initial recommended decision by May 1, 2003; the Judge has indicated she would request an extension. In December 2001, the NJBPU authorized the auctioning of BGS for the period from August 1, 2002 through July 31, 2003 to meet the electric demands of all customers who have not selected an alternative supplier. The auction, which ended on February 13, 2002 and was approved by the NJBPU on February 15, 2002, removed JCP&L's BGS obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. The auction provides a transitional mechanism and a different model for the procurement of BGS commencing August 1, 2003 may be adopted. Pennsylvania The Pennsylvania Public Utility Commission (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. 7 As a result of their generating asset divestitures, Met-Ed and Penelec obtain 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 rate relief. 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 are below their respective capped generation rates, that difference will reduce costs that had been deferred for recovery in future periods. This deferral accounting procedure will cease on December 31, 2005. Thereafter, costs which had been deferred through that date would be recoverable through application of competitive transition charge (CTC) revenues received by Met-Ed and Penelec through December 31, 2010. Met-Ed's and Penelec's PLR obligations extend through December 31, 2010; during that period CTC revenues will be applied first to PLR costs, then to non-NUG stranded costs and finally to NUG stranded costs. Met-Ed and Penelec would be 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 be written off at the time such nonrecovery becomes probable. Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to an affiliate company, FES, through a wholesale power sale. The PLR sale runs through the end of 2002 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 to FES. Met-Ed and Penelec will continue to defer those cost differences between NUG contract rates and the rates reflected in their capped generation rates. 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 Supreme Court of Pennsylvania. In September 2002, Met-Ed and Penelec established reserves for their PLR deferred energy costs which aggregated $287.1 million (Met-Ed $143.2 million and Penelec $143.9 million). The reserves reflect the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. In the interim financial statements in 2002, FirstEnergy, Met-Ed and Penelec had previously disclosed, in consultation with its independent accountants, that the finalization of that potential pre-acquisition contingency relating to the FirstEnergy/GPU merger would be reflected as an adjustment to the allocation of the purchase price prior to the end of the third quarter of 2002. In connection with FirstEnergy finalizing the purchase accounting relating to the FirstEnergy/GPU merger, in the third quarter of 2002, Met-Ed and Penelec, after further consultation with its independent accountants, revised the previously disclosed accounting for this potential pre-acquisition contingency. Accordingly, Met-Ed and Penelec will be amending the interim financial statements included in their Form 10-Q filings for the quarters ended March 31, 2002 and June 30, 2002 to reflect establishment of the reserve in the first quarter of 2002. The following tables summarize the impact on net income for Met-Ed and Penelec for the first and second quarters of 2002.
Met-Ed 3 Months Ended, 6 Months Ended, ------ ----------------------------- --------------- March 31, 2002 June 30, 2002 June 30, 2002 -------------- ------------- ------------- Net income as previously reported....... $19,118 $19,667 $38,785 Effect of revision...................... 7,494 (3,706) 3,788 ------- ------- ------- Net income as revised................... $26,612 $15,961 $42,573 ======= ======= =======
Penelec 3 Months Ended, 6 Months Ended, ------- ----------------------------- --------------- March 31, 2002 June 30, 2002 June 30, 2002 -------------- ------------- ------------- Net income as previously reported....... $14,147 $11,245 $25,392 Effect of revision...................... 4,692 (4,390) 302 ------- ------- ------- Net income as revised................... $18,839 $ 6,855 $25,694 ======= ======= =======
8 Their respective financial statements for the three months and nine months ended September 30, 2002, reflect the effect of the retroactive application. Since these revisions are not significant to FirstEnergy's consolidated financial statements for these periods, there will be no restatement of FirstEnergy's consolidated financial statements. FirstEnergy recorded an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) for the deferred costs incurred subsequent to the merger - $30.7 million ($17.9 million net of tax) by Met-Ed and $25.1 million ($14.7 million net of tax) by Penelec. The reserve for the remaining $231.3 million of deferred costs (Met-Ed-$112.5 million and Penelec-$118.8 million) increased goodwill by an aggregate net of tax amount of $135.3 million (Met-Ed-$65.8 million and Penelec-$69.5 million). 5 - NEW ACCOUNTING STANDARDS: The Financial Accounting Standards Board (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 will be tested for impairment at least on an annual basis - based on the results of the transition analysis, no impairment of goodwill is required. Prior to the adoption of SFAS 142, FirstEnergy amortized about $57 million ($.25 per share of common stock) of goodwill annually. There was no goodwill amortization in 2001 associated with the GPU merger under the provisions of the new standard. The following table shows what net income and earnings per share would have been if goodwill amortization, net of tax, had been excluded from prior periods:
Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- 2002 2001 2002 2001 ---- ---- ---- ---- (In thousands, except per share amounts) Reported net income.............................. $310,255 $234,087 $660,058 $477,814 Add back goodwill amortization (net of tax)...... -- 13,874 -- 41,013 -------- -------- -------- -------- Adjusted net income.............................. $310,255 $247,961 $660,058 $518,827 ======== ======== ======== ======== Basic earnings per common share: Reported earnings per share................... $1.06 $1.07 $2.25 $2.19 Goodwill amortization......................... -- 0.06 -- 0.19 ----- ----- ----- ----- Adjusted earnings per share................... $1.06 $1.13 $2.25 $2.38 ===== ===== ===== ===== Diluted earnings per common share: Reported earnings per share................... $1.05 $1.06 $2.24 $2.18 Goodwill amortization......................... -- 0.06 -- 0.19 ----- ----- ----- ----- Adjusted earnings per share................... $1.05 $1.12 $2.24 $2.37 ===== ===== ===== =====
The net change of $171 million in the goodwill balance as of September 30, 2002 of approximately $5.77 billion as compared to the December 31, 2001 balance of approximately $5.60 billion, primarily reflects the $135.3 million net of tax effect of the Pennsylvania PLR reserve of approximately $231.3 million as discussed in Note 4 - "Regulatory Matters - Pennsylvania" and further refinements of the initial purchase price allocation. 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. 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 various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the fourth quarter of 2002. In September 2001, the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144 supersedes SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The Statement also supersedes the accounting and reporting provisions of APB 30. FirstEnergy's adoption of this Statement, effective January 1, 2002, resulted in its accounting for any future impairments or disposals of long-lived assets under the provisions of SFAS 144, but did not change the accounting principles used in previous asset impairments or disposals. Application of SFAS 144 did not have a major impact on accounting for impairments or disposal transactions compared to the prior application of SFAS 121 or APB 30. 9 SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," 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 will be 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. On October 25, 2002, the Emerging Issues Task Force (EITF) reached a consensus in 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," to rescind EITF Issue No. 98-10 (and related interpretative guidance). Rescinding EITF No. 98-10 eliminates mark-to-market accounting for energy trading contracts that are not derivatives under SFAS 133. This guidance will be effective for all new contracts entered into after October 25, 2002 and the impact of its initial application will be reported as a change in accounting principle. Additionally, the EITF concluded that gains and losses on all derivative instruments under SFAS 133 that are held for trading purposes should be netted against related purchases or sales in the income statement. This new presentation requirement will be effective for periods beginning after December 15, 2002. FirstEnergy is not impacted by the rescission of EITF 98-10 and does not anticipate a material effect from the net presentation requirement. 6 - SEGMENT INFORMATION: FirstEnergy operates under the following reportable segments: regulated services, competitive services and other (primarily corporate support services and international operations). FirstEnergy's primary segment is regulated services, which include eight 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. Certain prior year amounts have been reclassified to conform with the current year presentation. 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 an alternative, competitive generation supplier. The regulated services segment obtains a portion of its required generation through power supply agreements with the competitive services segment. 10
Segment Financial Information ----------------------------- Regulated Competitive Reconciling Services Services Other Adjustments Consolidated --------- ----------- ----- ----------- ------------ (In millions) Three Months Ended: ------------------- September 30, 2002 ------------------ External revenues..................... $ 2,616 $ 934 $ 20 $ 2 (a) $ 3,572 Internal revenues..................... 261 452 116 (829) (b) -- Total revenues..................... 2,877 1,386 136 (827) 3,572 Depreciation and amortization......... 238 8 8 -- 254 Net interest charges.................. 140 17 77 (14) (b) 220 Income taxes.......................... 282 (10) (33) -- 239 Income before cumulative effect of a change in accounting............. 383 (15) (58) -- 310 Net income (loss)..................... 383 (15) (58) -- 310 Total assets.......................... 29,915 2,174 2,077 -- 34,166 Property additions.................... 150 69 56 -- 275 September 30, 2001 ------------------ External revenues..................... $ 1,457 $ 450 $ 2 $ 43 (a) $ 1,952 Internal revenues..................... 308 484 66 (858) (b) -- Total revenues..................... 1,765 934 68 (815) 1,952 Depreciation and amortization......... 197 7 7 -- 211 Net interest charges.................. 154 8 8 (46) (b) 124 Income taxes.......................... 188 (3) (4) -- 181 Income before cumulative effect of a change in accounting............. 246 (4) (8) -- 234 Net income (loss)..................... 246 (4) (8) -- 234 Total assets.......................... 15,460 2,113 505 -- 18,078 Property additions.................... 180 107 4 -- 291 Nine Months Ended: ------------------ September 30, 2002 ------------------ External revenues..................... $ 6,772 $2,308 $ 229 $ 14 (a) $ 9,323 Internal revenues..................... 793 1,279 358 (2,430) (b) -- Total revenues..................... 7,565 3,587 587 (2,416) 9,323 Depreciation and amortization......... 714 21 32 -- 767 Net interest charges.................. 458 34 282 (43) (b) 731 Income taxes.......................... 657 (47) (106) -- 504 Income before cumulative effect of a change in accounting............. 854 (68) (158) -- 628 Net income (loss)..................... 854 (68) (126) -- 660 Total assets.......................... 29,915 2,174 2,077 -- 34,166 Property additions.................... 414 179 102 -- 695 September 30, 2001 ------------------ External revenues..................... $ 4,026 $1,582 $ 4 $ 130 (a) $ 5,742 Internal revenues..................... 865 1,432 195 (2,492) (b) -- Total revenues..................... 4,891 3,014 199 (2,362) 5,742 Depreciation and amortization......... 608 15 22 -- 645 Net interest charges.................. 406 17 24 (76) (b) 371 Income taxes.......................... 413 (31) 3 -- 385 Income before cumulative effect of a change in accounting............. 528 (45) 3 -- 486 Net income (loss)..................... 528 (53) 3 -- 478 Total assets.......................... 15,460 2,113 505 -- 18,078 Property additions.................... 269 285 14 -- 568 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.
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FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------- ---------- ---------- ---------- 2002 2001 2002 2001 ---------- ---------- ---------- ---------- (In thousands, except per share amounts) REVENUES: Electric utilities..................................... $2,717,461 $1,437,023 $6,981,753 $4,008,823 Unregulated businesses................................. 854,874 514,623 2,341,447 1,732,710 ---------- ---------- ---------- ---------- Total revenues..................................... 3,572,335 1,951,646 9,323,200 5,741,533 ---------- ---------- ---------- ---------- EXPENSES: Fuel and purchased power............................... 1,388,830 300,526 2,916,472 925,633 Purchased gas.......................................... 95,799 121,564 447,980 647,938 Other operating expenses............................... 887,423 667,003 2,834,230 1,956,252 Provision for depreciation and amortization............ 253,917 210,764 767,450 644,584 General taxes.......................................... 176,850 112,292 493,944 323,900 ---------- ---------- ---------- ---------- Total expenses..................................... 2,802,819 1,412,149 7,460,076 4,498,307 ---------- ---------- ---------- ---------- INCOME BEFORE INTEREST AND INCOME TAXES................... 769,516 539,497 1,863,124 1,243,226 ---------- ---------- ---------- ---------- NET INTEREST CHARGES: Interest expense....................................... 212,477 114,468 685,824 349,029 Capitalized interest................................... (6,303) (7,016) (18,722) (28,135) Subsidiaries' preferred stock dividends................ 14,223 16,674 63,399 50,527 ---------- ---------- ---------- ---------- Net interest charges............................... 220,397 124,126 730,501 371,421 ---------- ---------- ---------- ---------- INCOME TAXES.............................................. 238,864 181,284 504,265 385,492 ---------- ---------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING.......................................... 310,255 234,087 628,358 486,313 Cumulative effect of accounting change (net of income taxes (benefit) of $13,600,000 and $(5,839,000), respectively)(Notes 1 and 3)........................... -- -- 31,700 (8,499) ---------- ---------- ---------- ---------- NET INCOME................................................ $ 310,255 $ 234,087 $ 660,058 $ 477,814 ========== ========== ========== ========== BASIC EARNINGS PER SHARE OF COMMON STOCK: Income before cumulative effect of accounting change... $1.06 $1.07 $2.14 $2.23 Cumulative effect of accounting change (net of income taxes) (Notes 1 and 3)...................................... -- -- .11 (.04) ----- ----- ----- ----- Net income........................................... $1.06 $1.07 $2.25 $2.19 ===== ===== ===== ===== WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING............................................ 293,328 218,594 293,066 218,358 ======= ======= ======= ======= DILUTED EARNINGS PER SHARE OF COMMON STOCK: Income before cumulative effect of accounting change... $1.05 $1.06 $2.13 $2.22 Cumulative effect of accounting change (net of income taxes) (Notes 1 and 3)...................................... -- -- .11 (.04) ----- ----- ----- ----- Net income........................................... $1.05 $1.06 $2.24 $2.18 ===== ===== ===== ===== WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING............................................ 294,277 220,165 294,385 219,470 ======= ======= ======= ======= DIVIDENDS DECLARED PER SHARE OF COMMON STOCK.............. $.375 $.375 $1.125 $1.125 ===== ===== ====== ====== The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.
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FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- -------------- (In thousands) ASSETS ------ CURRENT ASSETS: Cash and cash equivalents................................................. $ 280,547 $ 220,178 Receivables- Customers (less accumulated provisions of $69,382,000 and $65,358,000, respectively, for uncollectible accounts)............................. 1,139,367 1,074,664 Other (less accumulated provisions of $9,438,000 and $7,947,000, respectively, for uncollectible accounts)............................. 560,022 473,550 Materials and supplies, at average cost- Owned................................................................... 262,955 256,516 Under consignment....................................................... 156,530 141,002 Other..................................................................... 242,155 336,610 ----------- ----------- 2,641,576 2,502,520 ----------- ----------- ASSETS PENDING SALE (Note 3)................................................. 249,780 3,418,225 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT: In service................................................................ 20,363,677 19,981,749 Less-Accumulated provision for depreciation............................... 8,505,428 8,161,022 ----------- ----------- 11,858,249 11,820,727 Construction work in progress............................................. 684,859 607,702 ----------- ----------- 12,543,108 12,428,429 ----------- ----------- INVESTMENTS: Capital trust investments................................................. 1,095,586 1,166,714 Nuclear plant decommissioning trusts...................................... 1,024,332 1,014,234 Letter of credit collateralization........................................ 277,763 277,763 Pension investments....................................................... 295,018 273,542 Other..................................................................... 962,943 898,311 ----------- ----------- 3,655,642 3,630,564 ----------- ----------- DEFERRED CHARGES: Regulatory assets......................................................... 8,351,717 8,912,584 Goodwill.................................................................. 5,771,856 5,600,918 Other..................................................................... 951,875 858,273 ----------- ----------- 15,075,448 15,371,775 ----------- ----------- $34,165,554 $37,351,513 =========== ===========
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FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- -------------- (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... $ 1,477,925 $ 1,867,657 Short-term borrowings..................................................... 1,153,569 614,298 Accounts payable.......................................................... 789,846 704,184 Accrued taxes............................................................. 521,962 418,555 Other..................................................................... 1,119,752 1,064,763 ----------- ----------- 5,063,054 4,669,457 ----------- ----------- LIABILITIES RELATED TO ASSETS PENDING SALE (Note 3).......................... 106,308 2,954,753 ----------- ----------- CAPITALIZATION: Common stockholders' equity- Common stock, $.10 par value, authorized 375,000,000 shares - 297,636,276 shares outstanding........................................ 29,764 29,764 Other paid-in capital................................................... 6,113,191 6,113,260 Accumulated other comprehensive loss.................................... (118,730) (169,003) Retained earnings....................................................... 1,852,298 1,521,805 Unallocated employee stock ownership plan common stock - 4,202,566 and 5,117,375 shares, respectively.......................... (83,749) (97,227) ----------- ----------- Total common stockholders' equity................................... 7,792,774 7,398,599 Preferred stock of consolidated subsidiaries- Not subject to mandatory redemption..................................... 335,123 480,194 Subject to mandatory redemption......................................... 19,299 65,406 Subsidiary-obligated mandatorily redeemable preferred securities.......... 409,763 529,450 Long-term debt............................................................ 11,092,318 11,433,313 ----------- ----------- 19,649,277 19,906,962 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 2,697,511 2,684,219 Accumulated deferred investment tax credits............................... 241,792 260,532 Nuclear plant decommissioning costs....................................... 1,237,938 1,201,599 Power purchase contract loss liability.................................... 3,139,107 3,566,531 Other postretirement benefits............................................. 891,973 838,943 Other..................................................................... 1,138,594 1,268,517 ----------- ----------- 9,346,915 9,820,341 ----------- ----------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ----------- ----------- $34,165,554 $37,351,513 =========== =========== The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these balance sheets.
14
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ----------------------- ------------------------ 2002 2001 2002 2001 --------- --------- ---------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 310,255 $ 234,087 $ 660,058 $ 477,814 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 253,917 210,764 767,450 644,584 Nuclear fuel and lease amortization................ 20,191 23,247 60,754 71,448 Other amortization, net............................ (5,381) (3,111) (13,304) (10,783) Deferred costs recoverable as regulatory assets.... (152,336) -- (291,406) -- Deferred income taxes, net......................... 37,831 (29,749) 81,252 (65,057) Investment tax credits, net........................ (6,767) (4,980) (20,480) (14,966) Cumulative effect of accounting change............. -- -- (45,300) 14,338 Receivables........................................ (67,608) (69,509) (151,175) (45,924) Materials and supplies............................. (18,388) (16,068) (21,967) (60,330) Accounts payable................................... 47,888 79,982 85,662 (27,697) Accrued taxes...................................... 16,687 115,101 103,407 118,255 Accrued interest................................... 79,063 4,765 59,507 6,034 Other.............................................. 153,065 46,194 120,166 (126,397) --------- --------- ---------- --------- Net cash provided from operating activities...... 668,417 590,723 1,394,624 981,319 --------- --------- ---------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... 317,890 7,128 684,620 262,627 Short-term borrowings, net........................... 508,720 56,232 539,271 114,713 Redemptions and Repayments- Common stock......................................... -- -- -- 15,308 Preferred stock...................................... 313,517 6,000 503,816 16,716 Long-term debt....................................... 871,608 198,514 1,250,251 294,075 Common stock dividend payments......................... 109,963 81,942 329,565 245,559 --------- --------- ---------- --------- Net cash used for financing activities........... 468,478 223,096 859,741 194,318 --------- --------- ---------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... 274,923 291,276 694,614 567,774 Proceeds from sale of Midlands......................... -- -- (155,034) -- Avon cash and cash equivalents (Note 3)................ -- -- (31,326) -- Net assets held for sale............................... 33,385 -- 31,326 -- Cash investments....................................... 4,310 1,799 (59,712) (30,802) Other.................................................. (34,176) 104,177 (5,354) 123,693 --------- --------- ---------- --------- Net cash used for investing activities........... 278,442 397,252 474,514 660,665 --------- --------- ---------- --------- Net increase (decrease) in cash and cash equivalents...... (78,503) (29,625) 60,369 126,336 Cash and cash equivalents at beginning of period*......... 359,050 205,219 220,178 49,258 --------- --------- ---------- --------- Cash and cash equivalents at end of period*............... $ 280,547 $ 175,594 $ 280,547 $ 175,594 ========= ========= ========== ========= * Excludes amounts in "Assets Pending Sale" on the Consolidated Balance Sheets. The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.
15 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of FirstEnergy Corp.: We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of September 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2002. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2002 16 FIRSTENERGY CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FirstEnergy Corp. is a registered public utility holding company. Its subsidiaries and affiliates provide regulated and competitive electricity and other energy and energy-related services (see Results of Operations - Business Segments). FirstEnergy - which acquired the former GPU, Inc., in November 2001 - provides domestic regulated electric distribution services through its seven wholly owned electric utility subsidiaries. Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power Company (Penn) and The Toledo Edison Company (TE) provide regulated electric distribution services to customers in Ohio and Pennsylvania, and American Transmission Systems, Inc. provides transmission services. Metropolitan Edison Company (Met-Ed), Pennsylvania Electric Company (Penelec), and Jersey Central Power & Light Company (JCP&L) - which were acquired through the GPU merger - provide regulated electric distribution and transmission services to customers in Pennsylvania and New Jersey. Other FirstEnergy subsidiaries and affiliates sell energy and energy-related products and services, including electricity, natural gas and energy management services, in competitive markets. These products and services are often bundled under master contracts. Among FirstEnergy subsidiaries and affiliates supplying services in competitive markets are FirstEnergy Solutions (FES), MARBEL Energy Corporation, FirstEnergy Facilities Services Group, LLC, and MYR Group, Inc. FirstEnergy also offers electric services through international operations that were acquired in the GPU merger, including GPU Capital, Inc., and GPU Power, Inc. GPU Capital, Inc. and its subsidiaries provide electric distribution services and GPU Power, Inc., and its subsidiaries develop, own and operate electric generation facilities. Results of Operations --------------------- Net income in the third quarter of 2002 was $310.3 million, or basic earnings of $1.06 per share of common stock ($1.05 diluted), compared to $234.1 million, or basic earnings of $1.07 per share of common stock ($1.06 diluted) in the third quarter of 2001. During the first nine months of 2002, net income was $660.1 million, or basic earnings of $2.25 per share of common stock ($2.24 diluted), compared to net income of $477.8 million, or basic earnings of $2.19 per share of common stock ($2.18 diluted) in the first nine months of 2001. Results in the first nine months of 2002 and 2001 include the cumulative effect of accounting changes (described below). Before the cumulative effect of accounting changes, net income was $628.4 million in the first nine months of 2002, compared to $486.3 million for the same period of 2001. Basic earnings per share of common stock before the cumulative effect of accounting changes were $2.14 ($2.13 diluted) in the first nine months of 2002, compared to $2.23 ($2.22 diluted) in the first nine months of 2001. Results for the third quarter and first nine months of 2002 reflect the merger of FirstEnergy and GPU, which became effective on November 7, 2001, and therefore include the results of the former GPU companies. As a result of the merger, FirstEnergy issued nearly 73.7 million shares of its common stock, which are reflected in the calculation of earnings per share of common stock in the third quarter and year-to-date periods of 2002. Costs related to the extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration) reduced earnings by $0.19 per share in the third quarter and $0.28 per share in the year-to-date period of 2002. The table following this paragraph shows several one-time charges that resulted in a comparative net reduction to earnings of $0.13 per share of common stock in the third quarter and $0.27 per share of common stock in the first nine months of 2002, compared to the same periods of 2001. The third quarter 2002 results included a one-time non-cash charge of $0.11 per share that reflects the potential adverse impact of a Pennsylvania Supreme Court decision on whether to review a Commonwealth Court ruling that denied Met-Ed and Penelec the ability to defer the difference between their actual energy costs and those reflected in their capped generation rates (see State Regulatory Matters - Pennsylvania). In addition, Statement of Financial Accounting Standards No. (SFAS) 142, "Goodwill and Other Intangible Assets," implemented January 1, 2002, resulted in the cessation of goodwill amortization. In the third quarter and first nine months of 2001, amortization of goodwill reduced earnings per share of common stock (basic and diluted) by $0.06 and $0.19, respectively. One-time charges to earnings (discussed above) are summarized in the following table: 17
One-Time Charges ---------------- Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ---------------------- --------------------- 2002 2001 Change 2002 2001 Change ---- ---- ------ ---- ---- ------ (In millions) Pre-Merger Companies: --------------------- Severance costs - 2002............................ $11.3 $ -- $11.3 $ 11.3 -- $ 11.3 Early retirement costs - 2001..................... -- -- -- -- 8.8 (8.8) Long-term derivative contract adjustment.......... -- -- -- 18.1 -- 18.1 Equity investment - bankruptcy.................... -- -- -- 30.4 -- 30.4 Telecommunications investment writedown........... -- -- -- 10.1 -- 10.1 Generation project cancellation................... -- -- -- 17.1 -- 17.1 ----- ---- ----- ------ ----- ------ Total Pre-Merger Companies...................... 11.3 -- 11.3 87.0 8.8 78.2 Former GPU Companies: --------------------- Reserve - PA Supreme Court(1)..................... 55.8 -- 55.8 55.8 -- 55.8 Telecommunications investment writedown........... -- -- -- 2.5 -- 2.5 ----- ---- ----- ------ ----- ------ Total Former GPU Companies...................... 55.8 -- 55.8 58.3 -- 58.3 ----- ---- ----- ------ ----- ------ Total One-Time Charges.......................... $67.1 $ -- $67.1 $145.3 $ 8.8 $136.5 ===== ==== ===== ====== ===== ====== Effect on earnings per share of common stock (basic and diluted)............................... $0.13 $ -- $0.13 $ 0.29 $0.02 $ 0.27 ===== ==== ===== ====== ===== ====== (1) Represents a non-cash charge for the deferred costs incurred subsequent to the merger with GPU for the potential adverse impact of a pending Pennsylvania Supreme Court decision on whether to review the Commonwealth Court ruling. The reserve established in September 2002 increased reported purchased power costs for Met-Ed ($30.7 million) and Penelec ($25.1 million).
Revenues Total revenues increased $1.6 billion in the third quarter and $3.6 billion in the first nine months of 2002, compared to the same periods in 2001. Excluding results of the former GPU companies, total revenues increased by $263.0 million or 13.5% in the third quarter and decreased by $81.6 million or 1.4% in the first nine months of 2002, compared to the corresponding periods of 2001. Sources of changes in pre-merger and post-merger revenues during the third quarter and first nine months of 2002, compared with the corresponding periods of 2001, are summarized in the following table:
Sources of Revenue Changes -------------------------- Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Pre-Merger Companies: Electric Utilities (Regulated Services): Retail electric sales......................... $ (61.0) $ (278.8) Other revenues................................ 19.5 2.0 -------- -------- Total Electric Utilities........................ (41.5) (276.8) -------- -------- Unregulated Businesses (Competitive Services): Retail electric sales......................... 65.8 65.0 Wholesale electric sales...................... 317.4 442.0 Gas sales..................................... (12.8) (154.5) Other businesses.............................. (65.9) (157.3) -------- -------- Total Unregulated Businesses.................... 304.5 195.2 -------- -------- Total Pre-Merger Companies...................... 263.0 (81.6) -------- -------- Former GPU Companies: Electric utilities............................ 1,322.0 3,249.7 Unregulated businesses........................ 137.0 624.4 -------- -------- Total Former GPU Companies...................... 1,459.0 3,874.1 Intercompany Revenues........................... (101.3) (210.8) -------- -------- Net Revenue Increase............................ $1,620.7 $3,581.7 ======== ========
18 The following comparisons reflect variances for the pre-merger companies only, excluding the revenues of the former GPU companies in the third quarter and first nine months of 2002. Electric Sales Shopping by Ohio customers for alternative energy suppliers combined with a weak economy reduced retail electric sales revenues for FirstEnergy's pre-merger electric utility operating companies (EUOCs) by $61.0 million in the third quarter and $278.8 million in the first nine months of 2002, compared to the same periods of 2001. Kilowatt-hour sales to regulated retail customers decreased 9.4% in the third quarter and 15.5% in the first nine months of 2002, which reduced retail electric sales revenues by $48.9 million and $175.9 million, respectively. Sales of electric generation by alternative suppliers in the EUOCs' franchise areas increased to 25.8% of total energy delivered in the third quarter of 2002, compared to 15.1% in the same quarter last year. In the first nine months of 2002, the EUOCs' share of franchise-area sales declined by 12.6 percentage points, compared to the same period of 2001. Although generation kilowatt-hour sales continued to be adversely affected by economic conditions in the regional industrial base, the third quarter impact was moderated by a gradual recovery, as well as warmer summer weather, compared to the third quarter of 2001. Revenue from distribution deliveries increased by $16.1 million, partially offsetting the lower generation sales revenues in the third quarter of 2002, compared to the same quarter of 2001, due to an overall 3.6% net increase in kilowatt-hour deliveries to franchise customers. The net increase resulted from additional kilowatt-hour deliveries to residential customers (11.0% higher) and commercial and industrial customers (0.4% higher). Unusually hot summer weather increased the air-conditioning demand of residential customers compared to last year. During the first nine months of 2002, a 1.8% decline in kilowatt-hour deliveries to franchise customers reduced retail electric sales revenues by $26.0 million, compared to the same period in 2001. The reduced distribution deliveries resulted from a 4.4% reduction in deliveries to the commercial and industrial sectors, which were offset in part by a 4.7% increase in kilowatt-hour deliveries to residential customers. While some evidence of a modest economic recovery began in the first half of 2002, the recovery has not been broad based. 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 - $28.2 million in the third quarter and $76.6 million in the first nine months of 2002, compared to the same periods of 2001. These reductions to revenue are deferred for future recovery under FirstEnergy's Ohio transition plan and do not materially affect current period earnings. Retail electric sales revenue of the competitive services segment increased $65.8 million in the third quarter of 2002 resulting from a doubling of kilowatt-hour sales from the same quarter last year - accounting for all of the increase in retail electric sales revenue of the competitive services segment in the first nine months of 2002 compared to the same period of 2001. The increase in FirstEnergy's competitive kilowatt-hour sales in 2002 occurred primarily in Ohio. As of September 30, 2002, almost one-third of FirstEnergy's Ohio franchise-area customers serviced by alternative suppliers were supplied by FES. Wholesale revenues increased $318.9 million in the third quarter and $459.0 million in the year-to-date period of 2002, compared to the corresponding periods last year. Kilowatt-hour sales to the wholesale markets correspondingly more than doubled in the third quarter and first nine months of 2002, compared to the same periods last year. The higher kilowatt-hour sales resulted from increased availability of power for the wholesale market, due to additional internal generation and increased shopping by retail customers from alternative suppliers, which allowed FirstEnergy to take advantage of wholesale market opportunities. Nonaffiliated retail energy suppliers having access to 1,120 megawatts of FirstEnergy's generation capacity made available under its transition plan also contributed to the increase in sales to the wholesale market in the year-to-date period of 2002. Other Sales ----------- Other sales revenues declined by $78.7 million in the third quarter and $311.8 million in the first nine months of 2002 from the corresponding periods of 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 from decreased sales volume in the third quarter and lower prices in the year-to-date period of 2002, compared to the corresponding periods last year. Despite the reduced third quarter sales volume and lower prices in the first nine months of 2002, gross margins for gas sales improved (see Expenses). Reduced revenues from the facilities services group also contributed to the decrease in other sales revenue in the third quarter and year-to-date periods of 2002, compared to the same periods of 2001. 19 Expenses -------- Total expenses increased $1,390.7 million in the third quarter and $2,961.8 million in the first nine months of 2002, compared to the corresponding periods of 2001, including $1,185.3 million and $3,150.6 million of expenses related to the former GPU companies, respectively. For the pre-merger companies, total expenses increased by $308.0 million in the third quarter and $25.9 million in the first nine months of 2002, compared to the same periods of 2001. Sources of changes in pre-merger and post-merger companies' expenses in the third quarter and first nine months of 2002, compared to the prior year, are summarized in the following table: Sources of Expense Changes -------------------------- Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Pre-Merger Companies: Fuel and purchased power......... $ 385.1 $ 369.0 Purchased gas.................... (25.8) (200.0) Other operating expenses......... 2.4 (7.7) Depreciation and amortization.... (63.5) (168.2) General taxes.................... 9.8 32.8 -------- -------- Total Pre-Merger Companies....... 308.0 25.9 Former GPU Companies............... 1,185.3 3,150.6 Intercompany Expenses.............. (102.6) (214.7) -------- -------- Net Expense Increase............... $1,390.7 $2,961.8 ======== ======== The following comparisons reflect variances for the pre-merger companies only, excluding the expenses of the former GPU companies in the third quarter and first nine months of 2002. Fuel and purchased power costs increased by $385.1 million in the third quarter and by $369.0 million during the first nine months of 2002, compared to the same periods of 2001. Fuel expense increased in both the third quarter and first nine months of 2002 ($30.1 million and $90.2 million, respectively) principally due to additional internal generation and an increased mix of higher-cost fossil generation, as well as higher unit costs for coal consumed in the year-to-date period of 2002. An extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration) contributed to declines in nuclear generation of 15.1% and 11.6% in the third quarter and year-to-date periods of 2002 from the same periods in 2001. Fossil plant production increased significantly by 18.7% and 20.6% in the third quarter and first nine months of 2002, compared to the same periods of 2001. Overall, internal generation was 6.6% higher in the third quarter and 7.9% higher in the first nine months of 2002 than the corresponding periods of 2001. Purchased power costs increased $355.0 million in the third quarter and $278.8 million in the first nine months of 2002, compared to the same periods last year. The increases principally resulted from the additional purchased power volume required to support higher kilowatt-hour sales and reduced nuclear generation as a result of the Davis-Besse unplanned extended outage. Reduced purchase volumes and prices of natural gas in the third quarter and lower prices in the year-to-date period of 2002, compared to the corresponding periods last year, decreased purchased gas costs $25.8 million in the third quarter and $200.0 million for the first nine months of 2002 from the corresponding periods last year. The gross margins on gas sales improved by $13.0 million in the third quarter and $45.5 million in the first nine months of 2002 from the same periods last year. Other operating costs increased by $2.4 million in the third quarter and decreased by $7.7 million in the first nine months of 2002, compared to the corresponding periods of 2001. The slight increase in the third quarter resulted from several larger offsetting factors. Nuclear operating costs increased $4.8 million - $40.5 million in incremental costs associated with the extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration) were substantially offset by lower costs due to the absence in 2002 of a refueling outage that occurred in the third quarter of 2001. Higher employee benefits and other non-operating expenses ($26.7 million) were substantially offset by the elimination in the second half of 2001 of coal trading activities ($16.3 million) and reduced facilities service business ($15.4 million). The decrease in other operating costs for the nine-month period reflects several factors: elimination of coal trading ($104.5 million), reduced facilities services business ($39.4 million) and lower outage-related fossil plant expenditures ($39.7 million). Those reductions were more than offset by additional costs related to nuclear refueling and unplanned outages ($59.5 million), employee benefits and other non-operating expenses ($37.3 million) and several one-time charges of $87.0 million in 2002, summarized in the table on page 17. 20 Charges for depreciation and amortization decreased $63.5 million in the third quarter and $168.2 million in the first nine months of 2002 from the corresponding periods last year. These decreases resulted from several factors: shopping incentive deferrals and tax-related deferrals under the Ohio transition plan, the elimination of depreciation associated with the planned sale of four power plants and the cessation of goodwill amortization beginning January 1, 2002. FirstEnergy's goodwill amortization in the third quarter and year-to-date periods of 2001 totaled $14.4 million and $42.4 million, respectively. General taxes increased $9.8 million in the third quarter and $32.8 million in the first nine months of 2002 from the same periods in 2001. These increases were principally due to additional property taxes. The successful resolution of certain property tax issues in the second quarter of 2001 resulted in a one-time benefit of $15 million in that quarter, representing a portion of the increase in the nine-month period of 2002. Net Interest Charges Net interest charges increased $96.3 million in the third quarter and $359.1 million in the first nine months of 2002, compared to the same periods of 2001. These increases included interest of $69.6 million in the third quarter and $211.5 million in the first nine months of 2002 on $4 billion of long-term debt issued by FirstEnergy in connection with the merger. Excluding the results of the former GPU companies and the merger-related financing, net interest charges decreased by $24.5 million in the third quarter and $34.3 million in the first nine months of 2002 from the corresponding periods in 2001. Redemption and refinancing activities completed in the first nine months of 2002 totaled $1.059 billion and $430.7 million, respectively, and are expected to result in annualized savings of $96.9 million. FirstEnergy exchanged existing fixed-rate payments on outstanding debt (principal amount of $993.5 million) for short-term variable rate payments through interest rate swap transactions in June and July 2002. Net interest charges were reduced by $8.9 million in the third quarter of 2002 as a result of these swaps. Cumulative Effect of Accounting Changes Year-to-date earnings in 2002 and 2001 were affected by accounting changes. In connection with the November 2001 merger, certain former GPU international operations were identified as "assets pending sale." Subsequent to the merger date, results of operations and incremental interest costs related to these international subsidiaries were not included in FirstEnergy's Consolidated Statement of Income. On February 6, 2002, discussions began with Aquila, Inc. on modifying its initial offer for the acquisition of Avon Energy Partners Holdings, which resulted in a change in accounting for this investment, increasing net income in the first quarter of 2002 by $31.7 million. In the first quarter of 2001, FirstEnergy adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," resulting in an $8.5 million after-tax charge. Results of Operations - Business Segments ----------------------------------------- FirstEnergy manages its business as two separate major business segments - regulated services and competitive services. The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated domestic transmission and distribution systems. It also provides generation services to regulated franchise customers who have not chosen an alternative 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, 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 6 to the consolidated financial statements. Regulated Services Net income increased to $382.9 million in the third quarter of 2002 and $853.7 million in the first nine months of 2002, compared to $246.1 million and $527.9 million in the corresponding periods of 2001. Excluding results of the former GPU companies, net income increased by $7.6 million to $253.7 million in the third quarter and by $36.3 million to $564.1 million in the first nine months of 2002. The factors contributing to the increase in pre-merger net income are summarized in the following table: 21 Regulated Services ------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Revenues................................. $(105.8) $(365.9) Expenses................................. (88.0) (359.4) ------- ------- Income Before Interest and Income Taxes.. (17.8) (6.5) Net interest charges..................... (31.7) (82.9) Income taxes............................. 6.3 40.1 ------- ------- Net Income Increase...................... $ 7.6 $ 36.3 ======= ======= Lower generation sales and additional transition plan incentive credits combined to reduce revenues in the third quarter of 2002 from the same period in 2001. In the first nine months of 2002, retail generation sales and distribution throughput were both down, reflecting the combined impacts of tepid economic conditions and shopping by Ohio customers for alternative energy suppliers. Sales to FES were also lower, due to less available generation for sale because of the unplanned outage at Davis-Besse. Expenses were lower in the third quarter and first nine months of 2002 than the corresponding periods of 2001, primarily due to lower purchased power and depreciation and amortization. Lower generation sales reduced the need to purchase power from FES, which contributed to a $31.5 million expense decrease in the third quarter and a $153.0 million decrease in the first nine months of 2002, compared to the same periods last year. Depreciation and amortization declined by $65.2 million in the third quarter and $179.2 million in the first nine months of 2002, compared to the corresponding periods of 2001, due to new deferred regulatory assets under the Ohio transition plan, the elimination of depreciation associated with the planned sale of four power plants and the cessation of goodwill amortization beginning January 1, 2002. Other operating expenses also decreased by $47.4 million in the first nine months of 2002, compared to the same period last year. The majority of the decrease in other operating expenses resulted from reduced costs for jobbing and contracting work combined with a decline in uncollectible accounts expense. Net interest charges in the third quarter and year-to-date periods of 2002 decreased by $31.7 million and $82.9 million, respectively, from the corresponding periods of 2001, reflecting the impact of net debt and preferred stock redemptions and refinancings. Competitive Services The competitive services segment incurred a net loss of $14.0 million in the third quarter of 2002, compared to a net loss of $4.1 million in the same period of 2001. For the first nine months of 2002, the net loss increased to $67.3 million ($25.3 million net income excluding one-time charges) from $52.8 million in the first nine months of last year. Excluding results of the former GPU companies, the net loss was $16.4 million in the third quarter and $71.6 million in the first nine months of 2002. The factors contributing to the changes in pre-merger earnings are summarized in the following table: Competitive Services -------------------- Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Revenues.................................... $331.0 $166.5 Expenses.................................... 343.0 195.4 ------ ------ Income Before Interest and Income Taxes..... (12.0) (28.9) Net interest charges........................ 9.0 17.3 Income taxes................................ (8.6) (18.9) Cumulative effect of a change in accounting. -- 8.5 ------ ------ Net Income Decrease......................... $(12.4) $(18.8) ====== ====== The increased availability of power for the electric wholesale market, due to additional internal generation and reduced kilowatt-hour sales to affiliates, allowed FES to take advantage of additional wholesale market opportunities in 2002 - increasing sales by $317.4 million in the third quarter and $442.0 million in the first nine months of 2002, compared to the prior year. FES retail electric sales revenue contributed $65.8 million to the increase in the third quarter of 2002 and $65.0 million over the first nine months of 2002. As a result, electricity sales to non-affiliates increased $383.2 million in the 22 third quarter and $507.0 million in the first nine months of 2002 from the same periods last year. In the third quarter and first nine months of 2002, this increase was partially offset by reduced sales to regulated affiliates reflecting the impact of shopping by Ohio customers for alternative power providers, lower natural gas revenues resulting from reduced volumes in the third quarter and lower prices in the year-to-date period and less revenue from the facilities services group, resulting in a net $331.0 million increase in the third quarter and a $166.5 million increase in the year-to-date period. Expenses increased in the third quarter and first nine months of 2002, compared to the same periods of 2001. Higher third quarter and year-to-date expenses were primarily attributable to purchased power costs, which increased $355.0 million and $278.8 million, respectively. Additional kilowatt-hour sales and reduced nuclear generation, as a result of the extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration), combined to increase the volume of power purchased. Fuel costs increased in the third quarter and first nine months of 2002 ($30.1 million and $90.2 million, respectively), compared to the same periods last year, due to additional fossil generation; higher unit costs for coal consumed also added to fuel costs in the year-to-date period. Other operating expenses increased by $85.5 million in the first nine months of 2002, compared to the same period last year. The majority of the increase in other operating expenses resulted from additional nuclear operating costs (offset in part by lower outage-related fossil plant expenditures), severance costs and uncollectible account expense. Several one-time charges increased other operating expenses by $71.1 million in the first nine months of 2002 (see Expenses). Partially offsetting these expense increases in the third quarter and first nine months of 2002 were lower expenses from the facilities services group (principally resulting from reduced business activity) and reduced gas costs due to decreased sales in the third quarter and lower prices in the year-to-date period of 2002. Capital Resources and Liquidity ------------------------------- FirstEnergy and its subsidiaries have continuing cash needs for planned capital expenditures, maturing debt and preferred stock sinking fund requirements. During the last quarter of 2002, capital requirements for property additions and capital leases are expected to be about $342 million, including $27 million for nuclear fuel. These requirements also include $28 million of additional repair costs for the unplanned extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration). FirstEnergy has additional cash requirements of approximately $58.7 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2002. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. As of September 30, 2002, FirstEnergy and its subsidiaries had about $280.5 million of cash and temporary investments and $1.154 billion of short-term indebtedness. Available borrowings included $290.0 million from unused revolving lines of credit and $84 million from unused bank facilities at the end of the third quarter 2002. On November 8, 2002, FirstEnergy replaced its two maturing revolving lines of credit - $1.0 billion at FirstEnergy and $250 million at OE with a new FirstEnergy senior unsecured revolving credit facility of $1.0 billion which can be used to facilitate optional long-term debt and preferred stock redemptions to further reduce interest costs. Excluding property already released under the applicable mortgage indentures related to the planned sale of four power plants, OE, CEI, TE and Penn had the capability to issue $2.1 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds, as of September 30, 2002. JCP&L, Met-Ed and Penelec had the capability to issue $938.7 million of additional senior notes based upon FMB collateral, as of September 30, 2002. Based upon applicable charter earnings coverage tests through September 30, 2002, OE, Penn, TE and JCP&L could issue $3.4 billion of preferred stock (assuming no additional debt was issued). CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock. Off-balance sheet debt equivalents for sale and lease back transactions of generating units entered into in 1987 and accounts receivable factoring totaled $1.673 billion as of September 30, 2002. 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 ratings contingent collateralization provisions. As of September 30, 2002, outstanding guarantees and other assurances totaled $880.9 million as follows: 23 Guarantees and Other Assurances ------------------------------- (In millions) FirstEnergy Guarantees of Subsidiaries: Energy and Energy-Related Contracts....... $ 614.8 Financings (1)............................ 217.0 ------- 831.8 Surety Bonds................................ 25.8 Rating-Contingent Collateralization (2)..... 23.3 ------- Total Guarantees and Other Assurances..... $ 880.9 ======= (1) Includes parental guarantees of subsidiary debt and lease financing including FirstEnergy letters of credit supporting subsidiary debt. (2) Estimated net liability under contracts subject to rating-contingent collateralization provisions. 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 assets of FirstEnergy. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related activities is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees 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 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. Requirements of these provisions vary and typically require more than one rating reduction to below investment grade by Standard & Poor's or Moody's Investors Service to trigger additional collateralization by FirstEnergy. Postretirement Plans FirstEnergy maintains defined benefit pension plans, as well as several other postretirement employee benefit (OPEB) plans such as health care and life insurance. All of FirstEnergy's full-time employees are eligible to participate in these plans. In accordance with the provisions of the Employment Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded status of its pension plans annually to determine if additional funding is necessary. FirstEnergy has pre-funded a portion of the future liabilities related to its OPEB plans. Under the terms of its postretirement benefit plans, FirstEnergy reserves the right to change, modify or terminate the plans. Its pension plan funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA - no contributions have been required since 1985. Due to sharp declines in the equity markets in the United States since the second quarter of 2000, the value of assets held in the trusts to satisfy the obligations of pension plans has significantly decreased. As a result, under the minimum funding requirements of ERISA or the Pension Benefit Guaranty Corporation, FirstEnergy may be required to resume contributing to the plan trusts as early as 2004. FirstEnergy believes that it has adequate capital resources through cash generated from operations and through existing lines of credit to support necessary funding requirements based on anticipated plan performance. While OPEB plan assets have also been affected by the sharp declines in the equity market, contributions are voluntary and declines have a limited impact on required future funding. If the market value of FirstEnergy's pension plan assets were to remain unchanged from October 31, 2002, through the end of the year, it would be required to record an after-tax charge to equity (other comprehensive income) of approximately $328 million in the fourth quarter of 2002 to recognize its additional minimum pension liability of $637 million. The amount recorded will depend upon the financial markets and interest rates in the remainder of 2002. In addition, pension and other postretirement costs could increase by as much as $165 million in 2003 based on the reduction of plan assets through October 31, 2002, due to adverse equity market conditions, lower rate of return assumptions and the amortization of unrecognized losses, as well as higher health care trend rates for OPEB (see Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting). 24 Market Risk Information ----------------------- FirstEnergy uses various market sensitive instruments, including derivative contracts, primarily to manage the risk of price, interest rate and foreign currency fluctuations. 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. Commodity Price Risk FirstEnergy is exposed to market risk primarily due to fluctuations in electricity, natural gas and coal prices. 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 much lesser extent, for trading purposes. Most of FirstEnergy's 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:
Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 --------------------------- --------------------------- Non-Hedge Hedge Total Non-Hedge Hedge Total --------- ----- ----- --------- ----- ----- (In millions) Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset at beginning of period........... $14.8 $(12.8) $ 2.0 $ 9.9 $(76.2) $(66.3) New contract value when entered........................ -- -- -- -- 2.1 2.1 Additions/Increase in value of existing contracts...... 13.7 20.0 33.7 40.9 52.8 93.7 Change in techniques/assumptions....................... -- -- -- (20.1) -- (20.1) Settled contracts...................................... 7.9 1.8 9.7 5.7 30.3 36.0 ---------------------------- ------------------------------ Outstanding net asset at end of period (1)............. 36.4 9.0 45.4 36.4 9.0 45.4 ---------------------------- ------------------------------ Non-commodity net assets at end of period: Interest Rate Swaps (2)............................. -- 37.3 37.3 -- 37.3 37.3 ---------------------------- ------------------------------ Net Assets - Derivatives Contracts (3)................. $36.4 $ 46.3 $82.7 $ 36.4 $ 46.3 $ 82.7 ============================ ============================== Impact of Changes in Commodity Derivative Contracts(4) Income Statement Effects (Pre-Tax)..................... $17.8 $ -- $17.8 $ 4.7 $ -- $ 4.7 Balance Sheet Effects: Other Comprehensive Income (Pre-Tax)................ $ -- $ 21.8 $21.8 $ -- $ 83.1 $ 83.1 Regulatory Liability................................ $ 3.8 $ -- $ 3.8 $ 21.8 $ -- $ 21.8
Derivatives included on the Consolidated Balance Sheet as of September 30, 2002: Non-Hedge Hedge Total --------- ----- ----- (In millions) Current- Other Assets................ $ 20.4 $ 7.4 $ 27.8 Other Liabilities........... (20.8) (12.1) (32.9) Non-Current- Other Deferred Charges...... 40.7 52.9 93.6 Other Deferred Credits...... (3.9) (1.9) (5.8) ------ ------ ------ Net assets................ $ 36.4 $ 46.3 $ 82.7 ====== ====== ====== (1) Includes $26 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Interest rate swaps are treated as fair value hedges. Changes in derivative values are offset by changes in the hedged debts' premium or discount. (3) Excludes $0.6 million of derivative contract fair value decrease, as of September 30, 2002, representing FirstEnergy's 50% share of Great Lakes Energy Partners, LLC. (4) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. 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, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy utilizes these results in developing estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: 25 Source of Information - Fair Value by Contract Year --------------------------------------------------- 2002(1) 2003 2004 Thereafter Total ---- ---- ---- ---------- ----- (In millions) Prices actively quoted...... $(0.9) $15.7 $(1.1) $(0.6) $13.1 Prices based on models(2)... -- -- -- 32.3 32.3 ------------------------------------------------ Total................... $(0.9) $15.7 $(1.1) $31.7 $45.4 ================================================= (1) For the last quarter of 2002. (2) Includes $26 million from an embedded option that is offset by a regulatory liability and does not affect earnings. FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both FirstEnergy's trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of September 30, 2002. FirstEnergy estimates that if energy commodity prices experienced an adverse 10 percent change, net income for the next twelve months would decrease by approximately $6.4 million. State Regulatory Matters ------------------------ Ohio The transition cost portion of FirstEnergy's Ohio EUOC 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, FirstEnergy assumed the risk of not recovering up to $500 million of transition costs if the rate of customers (excluding contracts and full-service accounts) switching their service from OE, CEI and TE had not reached 20% for any consecutive twelve-month period by December 31, 2005 - the end of the market development period. Based on actual shopping levels attained through October 2002, FirstEnergy has achieved all of its required 20% customer shopping goals, and there is therefore no longer risk of regulatory action reducing the recoverable transition costs. New Jersey On August 1, 2002, FirstEnergy submitted two rate filings for JCP&L with the New Jersey Board of Public Utilities (NJBPU). The first filing is a request to increase base electric rates by $98 million annually, an average of 5%. The second filing is a request to recover deferred costs associated with mandated purchase-power contracts with non-utility generators and providing Basic Generation Service to customers in excess of the state's generation rate cap. As of September 30, 2002, the accumulated deferred cost balance totaled approximately $482 million. The deferral filing would result in an additional 2.8% increase in rates, assuming the use of securitization. The securitization methodology is similar to the Oyster Creek securitization completed in May 2002. The NJBPU has directed the Office of Administrative Law to have its Administrative Law Judge issue a recommended decision by May 1, 2003; the Judge has indicated she would request an extension. The rates established in this proceeding will become effective August 1, 2003. Pennsylvania Several parties had filed Petitions for Review in June and July 2001 with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders which approved the FirstEnergy/GPU merger and provided Met-Ed and Penelec rate relief. 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 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 Supreme Court of Pennsylvania. In September 2002, Met-Ed and Penelec established reserves for their PLR deferred energy costs which aggregated $287.1 million (Met-Ed $143.2 million and Penelec $143.9 million). The reserves reflect 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) for the deferred costs incurred subsequent to the merger - $30.7 million ($17.9 million net of tax) by Met-Ed and $25.1 million ($14.7 million net of tax) by Penelec. The reserve for the remaining $231.3 million (Met-Ed - $112.5 million and Penelec - $118.8 million) of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million (Met-Ed-$65.8 million and Penelec-$69.5 million). 26 Sale of Power Plants -------------------- In November 2001, FirstEnergy announced an agreement to sell four of its older coal-fired power plants located along Lake Erie in Ohio to NRG (see Note 3). 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 is reserving 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. FirstEnergy is pursuing opportunities with other parties who have expressed interest in purchasing the plants. It expects to conclude a bid process with interested parties in the fourth quarter of 2002, with the objective of executing an acceptable sales agreement by year-end. If FirstEnergy has not executed a sales agreement by year-end, it would need to reflect up to $58 million of unrecognized depreciation and other transaction costs. Emdersa Divestiture ------------------- 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 has determined that it is not probable that the subsequent economic conditions in Argentina have eroded the fair value recorded for Emdersa; as a result, an impairment writedown of this investment is not warranted as of September 30, 2002. FirstEnergy continues to assess the potential impact of these and other related events on the realizability of the value recorded for Emdersa. FirstEnergy continues to pursue divesting Emdersa and, in accordance with EITF Issue No. 87-11, has classified its assets and liabilities in the Consolidated Balance Sheet as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale." FirstEnergy believes it is probable that a completed sale or a definitive agreement to sell its interest in Emdersa could be achieved in 2002. Potential investors recently retained a financial advisor to assist in the due diligence process and FirstEnergy believes it is probable that preliminary negotiations with those investors will be completed in 2002. If FirstEnergy does not sell Emdersa - an Argentinean distribution company that FirstEnergy acquired through its merger with GPU - or reach a definite agreement to do so in 2002, FirstEnergy could no longer include Emdersa as an asset pending sale on its consolidated balance sheet. As a result, FirstEnergy would include any income or loss generated by Emdersa after that day, or the date that a sale is considered not probable, in its consolidated statement of income. In addition, FirstEnergy would recognize a one-time, non-cash cumulative effect of a change in accounting to reflect Emdersa's cumulative results from November 7, 2001 - the effective date of the merger with GPU - through the date that it becomes probable that a definitive agreement to sell would not be achieved in 2002. Based on results through September 30, 2002, the amount of such a one-time, after-tax charge would be approximately $94 million, or $0.32 per share. Davis-Besse Restoration ----------------------- On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FirstEnergy 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. FirstEnergy expects to complete refurbishment and installation of the replacement reactor head as well as any other work related to restart of the plant early in 2003. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. The estimated costs (capital and expense) associated with the extended Davis-Besse outage in 2002 and 2003 are: 27 Costs of Davis-Besse Extended Outage ------------------------------------ Expenditure Range ----------------- (In millions) 2002 ---- Replace reactor vessel head (principally capital expenditures). $55 - $75 Primarily operating expenses (pre-tax): Additional maintenance (including acceleration of programs).... $115 - $135 Replacement power through September 2002....................... $85 Replacement power for October through December 2002............ $30 - $45 2003 ---- Additional work to enhance reliability and performance......... $50 The replacement power costs for 2003 are estimated to be $10-$15 million per month. FirstEnergy has fully hedged its on-peak replacement energy supply for Davis-Besse through the end of 2002 and has completed some hedging in 2003 as well. Provider of Last Resort ----------------------- FirstEnergy continues to enter into power contracts to cover its "provider of last resort" obligations for the 2003-2005 period. Market conditions are currently favorable, therefore minimizing FirstEnergy's exposure to the commodity market. FirstEnergy is now nearly 100% hedged for 2003, 95% hedged for 2004 and 88% hedged for 2005 projected obligations. Environmental Matters --------------------- The EUOCs 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 September 30, 2002, based on estimates of the total costs of cleanup, the EUOCs' 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 a non-bypassable societal benefits charge. The EUOCs have total accrued liabilities aggregating approximately $57.9 million as of September 30, 2002. FirstEnergy does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Significant Accounting Policies ------------------------------- FirstEnergy prepares its 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 FirstEnergy's 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. FirstEnergy's 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 preliminary purchase price allocations for the GPU acquisition are subject to adjustment in 2002 when finalized. Regulatory Accounting FirstEnergy's 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 FirstEnergy is 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 FirstEnergy operates, a significant amount of regulatory assets have been recorded - $8.4 billion as of September 30, 2002. FirstEnergy regularly reviews these assets to 28 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. FirstEnergy continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, FirstEnergy enters into significant commodity contracts, as well as interest rate and currency swaps, which increase the impact of derivative accounting judgments. Revenue Recognition FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and assumptions of future activities. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation. 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. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension benefits. Corporate bond yields, as well as interest rates in general, have declined in the first nine months of 2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If the discount rate is reduced below the current assumed rate, liabilities and pension and OPEB costs would increase in 2003. FirstEnergy's assumed rate of return on its pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2001, 2000 and 1999, plan assets have earned (5.5%), (0.3%) and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed assuming a 10.25% rate of return on plan assets, consistent with long-term historical returns produced by the plan's investment portfolio. 29 If a lower rate of return were to be assumed in 2003, FirstEnergy's reported pension costs would increase. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is moderated due to smaller asset balances. However, medical cost trends have significantly increased and could affect future postretirement benefit costs. As a result of the reduced market value of its pension plan assets (see Postretirement Plans), FirstEnergy could be required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits." The offset to the liability would be recorded as a reduction to common stockholders' equity through an after-tax charge to other comprehensive income (OCI), and would not affect net income for 2002. The charge to OCI would reverse in future periods to the extent the fair value of trust assets would exceed the accumulated benefit obligation. The amount of pension liability to be recorded as of December 31, 2002, will depend upon the discount rate and asset returns experienced in 2002 (and any resulting change in FirstEnergy's assumptions). Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," FirstEnergy periodically evaluates its 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, FirstEnergy recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," FirstEnergy evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. The accounting standard requires that 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 FirstEnergy 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. FirstEnergy's annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill. As of September 30, 2002, FirstEnergy had $5.8 billion of goodwill that primarily relates to its regulated services segment. Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- 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 as of January 1, 2003. SFAS 143 requires the fair value of a liability for an asset retirement obligation to 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, both resulting in a period expense. 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 various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the fourth quarter of 2002. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," issued by the Financial Accounting Standards Board 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 will be 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. On October 25, 2002, the Emerging Issues Task Force (EITF) reached a consensus in 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," to rescind EITF Issue No. 98-10 (and related interpretative guidance). Rescinding EITF No. 98-10 eliminates mark-to-market accounting for energy trading contracts that are not derivatives under SFAS 133. This guidance will be effective for all new contracts entered into after October 25, 2002 and the impact of its initial application will be reported as a change in accounting principle. Additionally, the EITF concluded that gains and losses on all derivative instruments under SFAS 133 that are held for trading purposes should be netted against related purchases or sales in the income statement. This new presentation requirement will be effective for periods beginning after December 15, 2002. FirstEnergy is not impacted by the rescission of EITF 98-10 and does not anticipate a material effect from the net presentation requirement. 30
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, --------------------- ------------------------ 2002 2001 2002 2001 -------- -------- ---------- ---------- (In thousands) OPERATING REVENUES........................................ $813,296 $815,695 $2,265,645 $2,343,510 -------- -------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel................................................... 15,649 12,484 45,068 40,038 Purchased power........................................ 243,475 271,201 698,126 815,413 Nuclear operating costs................................ 79,388 117,918 255,322 287,150 Other operating costs.................................. 94,820 80,611 252,928 241,283 -------- -------- ---------- ---------- Total operation and maintenance expenses............. 433,332 482,214 1,251,444 1,383,884 Provision for depreciation and amortization............ 82,691 104,302 266,342 325,463 General taxes.......................................... 47,254 43,604 135,154 114,691 Income taxes........................................... 95,517 63,087 222,535 170,228 -------- -------- ---------- ---------- Total operating expenses and taxes................... 658,794 693,207 1,875,475 1,994,266 -------- -------- ---------- ---------- OPERATING INCOME.......................................... 154,502 122,488 390,170 349,244 OTHER INCOME.............................................. 14,212 18,695 29,811 48,881 -------- -------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES........................ 168,714 141,183 419,981 398,125 -------- -------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt............................. 29,548 36,978 92,933 115,892 Allowance for borrowed funds used during construction and capitalized interest............................. (1,018) (573) (2,522) (1,879) Other interest expense................................. 2,889 4,963 10,837 17,681 Subsidiaries' preferred stock dividend requirements.... 2,276 3,626 9,528 10,878 -------- -------- ---------- ---------- Net interest charges................................. 33,695 44,994 110,776 142,572 -------- -------- ---------- ---------- NET INCOME................................................ 135,019 96,189 309,205 255,553 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 658 2,702 5,851 8,106 -------- -------- ---------- ---------- EARNINGS ON COMMON STOCK.................................. $134,361 $ 93,487 $ 303,354 $ 247,447 ======== ======== ========== ========== The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.
31
OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- -------------- (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $4,964,114 $4,979,807 Less-Accumulated provision for depreciation............................... 2,496,400 2,461,972 ---------- ---------- 2,467,714 2,517,835 ---------- ---------- Construction work in progress- Electric plant.......................................................... 116,172 87,061 Nuclear fuel............................................................ 3,146 11,822 ---------- ---------- 119,318 98,883 ---------- ---------- 2,587,032 2,616,718 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: PNBV Capital Trust........................................................ 415,664 429,040 Letter of credit collateralization........................................ 277,763 277,763 Nuclear plant decommissioning trusts...................................... 285,835 277,337 Long-term notes receivable from associated companies...................... 504,133 505,028 Other..................................................................... 292,060 303,409 ---------- ---------- 1,775,455 1,792,577 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 45,785 4,588 Receivables- Customers (less accumulated provisions of $5,349,000 and $4,522,000, respectively, for uncollectible accounts)............................. 344,795 311,744 Associated companies.................................................... 481,047 523,884 Other (less accumulated provisions of $1,000,000 for uncollectible accounts at both dates)............................................... 36,946 41,611 Notes receivable from associated companies................................ 409,607 108,593 Materials and supplies, at average cost- Owned................................................................... 57,778 53,900 Under consignment....................................................... 18,566 13,945 Other..................................................................... 17,477 50,541 ---------- ---------- 1,412,001 1,108,806 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 2,070,556 2,234,227 Other..................................................................... 162,533 163,625 ---------- ---------- 2,233,089 2,397,852 ---------- ---------- $8,007,577 $7,915,953 ========== ==========
32
OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- -------------- (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: Common stockholder's equity- Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding................................................ $2,098,729 $2,098,729 Retained earnings....................................................... 753,726 572,272 ---------- ---------- Total common stockholder's equity................................... 2,852,455 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......................................... 14,250 14,250 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures................................................. -- 120,000 Long-term debt............................................................ 1,265,033 1,614,996 ---------- ---------- 4,231,808 4,620,317 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 532,089 576,962 Short-term borrowings- Associated companies.................................................... 401,084 26,076 Other................................................................... 166,716 219,750 Accounts payable- Associated companies.................................................... 122,306 110,784 Other................................................................... 7,526 19,819 Accrued taxes............................................................. 481,393 258,831 Accrued interest.......................................................... 33,016 33,053 Other..................................................................... 99,433 63,140 ---------- ---------- 1,843,563 1,308,415 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 1,101,118 1,175,395 Accumulated deferred investment tax credits............................... 89,647 99,193 Nuclear plant decommissioning costs....................................... 284,997 276,500 Other postretirement benefits............................................. 172,737 166,594 Other..................................................................... 283,707 269,539 ---------- ---------- 1,932,206 1,987,221 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $8,007,577 $7,915,953 ========== ========== The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.
33
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2002 2001 2002 2001 -------- -------- -------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $135,019 $ 96,189 $309,205 $ 255,553 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 82,691 104,302 266,342 325,463 Nuclear fuel and lease amortization................ 12,389 10,125 35,924 33,802 Deferred income taxes, net......................... (9,782) (9,182) (31,838) (51,744) Investment tax credits, net........................ (3,751) (3,331) (11,286) (10,025) Receivables........................................ (18,352) (26,425) 14,451 (221,220) Materials and supplies............................. (3,699) 5,815 (8,499) 59,875 Accounts payable................................... 18,690 (4,888) (771) (57,572) Accrued taxes...................................... 16,302 31,296 222,562 49,507 Other.............................................. 44,883 48,727 39,240 2,100 -------- -------- -------- --------- Net cash provided from operating activities...... 274,390 252,628 835,330 385,739 -------- -------- -------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... 14,500 6,619 14,500 256,161 Short-term borrowings, net........................... 348,132 80,346 321,974 64,899 Redemptions and Repayments- Preferred stock...................................... 220,000 5,000 220,000 5,000 Long-term debt....................................... 182,595 178,039 411,336 215,749 Dividend Payments- Common stock......................................... 20,700 100,000 121,900 137,300 Preferred stock...................................... 658 2,668 5,851 8,072 -------- -------- -------- --------- Net cash used for financing activities........... 61,321 198,742 422,613 45,061 -------- -------- -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... 32,130 49,908 87,851 90,914 Loans to associated companies.......................... 165,340 71,900 300,665 383,729 Loan payments from associated companies................ -- -- (546) (506) Sale of assets to associated companies................. -- -- -- (154,596) Other.................................................. (6,047) 13,199 (16,450) 7,153 -------- -------- -------- --------- Net cash used for investing activities........... 191,423 135,007 371,520 326,694 -------- -------- -------- --------- Net increase (decrease) in cash and cash equivalents...... 21,646 (81,121) 41,197 13,984 Cash and cash equivalents at beginning of period.......... 24,139 113,374 4,588 18,269 -------- -------- -------- --------- Cash and cash equivalents at end of period................ $ 45,785 $ 32,253 $ 45,785 $ 32,253 ======== ======== ======== ========= The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.
34 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Ohio Edison Company: We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of September 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2002. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2002 35 OHIO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION OE is a wholly owned, electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. OE and Penn (OE Companies) also provide generation services to those customers electing to retain them as their power supplier. The OE Companies provide power directly to wholesale customers under previously negotiated contracts, as well as to alternative energy suppliers under OE's transition plan. The OE Companies have unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of the OE Companies are provided by FES - an affiliated company. Results of Operations --------------------- Operating revenues decreased $2.4 million or 0.3% in the third quarter of 2002 and $77.9 million or 3.3% in the first nine months of 2002, as compared to the corresponding periods of 2001. Changes in operating revenues reflect the combined effects of a weak but recovering economy, shopping by Ohio customers for alternative energy providers, changes in revenues from wholesale customers and weather. Retail kilowatt-hour sales declined by 6.2% in the third quarter and 10.2% in the first nine months of 2002, compared to the same periods of 2001, with declines in all customer sectors (residential, commercial and industrial), resulting in a $16.0 million and a $56.9 million reduction in generation sales revenue, respectively. OE's lower generation kilowatt-hour sales in both periods resulted principally from customer choice in Ohio. Sales of electric generation by alternative suppliers as a percent of total sales delivered in the OE Companies' franchise area increased to 23.6% in the third quarter of 2002 from 16.4% in the same period last year. During the first nine months of 2002, OE's share of electric generation sales in its franchise areas decreased by 8.7 percentage points, compared to the same period of 2001. Distribution deliveries increased 2.6% in the third quarter of 2002, which increased revenues from electricity throughput by $22.4 million, compared with the third quarter of 2001. The third quarter of 2002 benefited from a slight improvement in economic activity and unusually hot summer weather. Despite a stronger third quarter performance, distribution deliveries were lower in the first nine months of 2002, compared to the same period last year, declining by 0.4% primarily due to the weaker economic environment earlier in the year. Distribution revenues increased $15.4 million in the year-to-date period as higher residential revenues were partially offset by lower industrial revenues. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, further reduced operating revenues in the third quarter and first nine months of 2002, compared to the corresponding periods of 2001 - reducing comparable revenues by $9.7 million and $26.3 million, respectively. These revenue reductions are deferred for future recovery under OE's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers increased by $4.6 million in the third quarter of 2002, compared to the third quarter of 2001, as a result of increased kilowatt-hour sales to nonaffiliated wholesale customers and to FES. Sales revenues from wholesale customers were $5.6 million lower in the nine-month period of 2002, compared to the same period last year. Increased revenues from kilowatt-hour sales to nonaffiliated wholesale customers were more than offset by reduced revenues from FES. The sources of changes in operating revenues during the third quarter and first nine months of 2002, compared with the corresponding periods of 2001, are summarized in the following table: Sources of Operating Revenue Changes ------------------------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Retail: Generation sales.................... $(16.0) $(56.9) Distribution deliveries............. 22.4 15.4 Increased shopping incentives....... (9.7) (26.3) ------ ------ Total Retail........................ (3.3) (67.8) Wholesale............................. 4.6 (5.6) Other................................. (3.7) (4.5) ------ ------ Net Decrease in Operating Revenue..... $ (2.4) $(77.9) ====== ====== 36 Operating Expenses and Taxes Total operating expenses and taxes declined $34.4 million and $118.8 million in the third quarter and the first nine months of 2002, respectively, compared to the corresponding periods of 2001. Purchased power costs decreased $27.7 million in the third quarter and $117.3 million in the first nine months of 2002, compared to the same periods last year, due to lower unit costs. Reduced volume requirements supporting lower generation kilowatt-hour sales also contributed to decreased purchased power costs for the first nine months of 2002, compared to the same period in 2001. Nuclear operating costs decreased $38.5 million in the third quarter of 2002, compared to the corresponding period last year, primarily due to the absence of a refueling outage in the third quarter of 2002; Beaver Valley Unit 1 (100% owned) experienced a refueling outage in the third quarter of 2001. In the first nine months of 2002, nuclear operating costs decreased by $31.8 million from the same period last year. Additional nuclear operating costs related to the first quarter 2002 refueling outage at Beaver Valley Unit 2 (55.62% owned) that exceeded refueling outage costs for the Perry Plant (35.24% owned) in the same period of 2001 were more than offset by the absence of a nuclear refueling outage in the third quarter of 2002. Other operating costs increased $14.2 million and $11.6 million in the third quarter and first nine months of 2002, respectively, compared to the same periods last year, primarily due to employee severance costs and higher distribution expenses in the third quarter of 2002. Charges for depreciation and amortization decreased by $21.6 million in the third quarter and $59.1 million in the first nine months of 2002, compared to the same periods last year. These decreases reflect higher shopping incentive deferrals and tax-related deferrals under OE's transition plan in 2002. General taxes increased by $3.7 million in the third quarter and $20.5 million in the first nine months of 2002 from the same periods in 2001. Increased property taxes and a higher gross receipts tax rate for 2002 contributed to the increase in general taxes for both periods. The successful resolution of certain property tax issues in the second quarter of 2001 provided a one-time benefit of $15 million in that year. Other Income Other income decreased $4.5 million in the third quarter and $19.1 million in the first nine months of 2002 from the corresponding periods of 2001. Reduced interest income was the principal factor in the third quarter decrease. A large part of the reduction for the year-to-date period resulted from a first quarter 2002 adjustment related to OE's low income housing investments. Net Interest Charges Net interest charges continued to trend lower, decreasing by $11.3 million in the third quarter and $31.8 million in the first nine months of 2002, compared to the same periods last year, primarily due to redemption and refinancing activities. During the first nine months of 2002, maturing debt and preferred stock redemption and refinancing transactions totaled $407.6 million and $134.5 million, respectively, and will result in annualized savings of $43.3 million. Capital Resources and Liquidity ------------------------------- The OE Companies have continuing cash requirements for planned capital expenditures and maturing debt. During the fourth quarter of 2002, capital requirements for property additions and capital leases are expected to be about $54 million, including $17 million for nuclear fuel. The OE Companies also have sinking fund requirements for preferred stock and maturing long-term debt of $15.4 million. These requirements are expected to be satisfied from internal cash and/or short-term credit arrangements. As of September 30, 2002, the OE Companies had about $455.4 million of cash and temporary investments and $567.8 million of short-term indebtedness. Their available borrowing capability included $250.0 million from unused revolving lines of credit and $34 million from unused bank facilities at the end of the third quarter of 2002. On November 8, 2002, FirstEnergy replaced two maturing revolving lines of credit totaling $1.25 billion, including $250 million at OE, with a new FirstEnergy senior unsecured revolving credit facility of $1.0 billion. As of September 30, 2002, the OE Companies had the capability to issue up to $1.7 billion of additional first mortgage bonds on the basis of property additions and retired bonds. Under the earnings coverage tests contained in the OE Companies' charters, $3.1 billion of preferred stock (assuming no additional debt was issued) could be issued based on earnings through the third quarter of 2002. Off-balance sheet debt equivalents for sale and leaseback transactions of generating units entered into in 1987 totaled $703 million as of September 30, 2002. Postretirement Plans FirstEnergy maintains defined benefit pension plans, as well as several other postretirement employee benefit (OPEB) plans such as health care and life insurance. All of the OE Companies full-time employees are eligible to participate in these plans. In accordance with the provisions of the Employment Retirement Income Security Act of 1974 (ERISA), 37 FirstEnergy reviews the funded status of its pension plans annually to determine if additional funding is necessary. FirstEnergy has pre-funded a portion of the future liabilities related to its OPEB plans. Under the terms of its postretirement benefit plans, FirstEnergy reserves the right to change, modify or terminate the plans. Its pension plan funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA - no contributions have been required since 1985. Due to sharp declines in the equity markets in the United States since the second quarter of 2000, the value of assets held in the trusts to satisfy the obligations of pension plans has significantly decreased. As a result, under the minimum funding requirements of ERISA or the Pension Benefit Guaranty Corporation, FirstEnergy may be required to resume contributing to the plan trusts as early as 2004. FirstEnergy believes that it has adequate capital resources through cash generated from operations and through existing lines of credit to support necessary funding requirements based on anticipated plan performance. While OPEB plan assets have also been affected by the sharp declines in the equity market, contributions are voluntary and declines have a limited impact on required future funding. If the market value of FirstEnergy's pension plan assets were to remain unchanged from October 31, 2002, through the end of the year, the OE Companies would be required to record an after-tax charge to equity (other comprehensive income) of approximately $136 million in the fourth quarter of 2002 to recognize their additional minimum pension liability of $242 million. The amount recorded will depend upon the financial markets and interest rates in the remainder of 2002. In addition, pension and other postretirement costs could increase by as much as $11 million in 2003 based on the reduction of plan assets through October 31, 2002, due to adverse equity market conditions, lower rate of return assumptions and the amortization of unrecognized losses, as well as higher health care trend rates for OPEB (see Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting). State Regulatory Matters ------------------------ The transition cost portion of the OE Companies' 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, OE assumed the risk of not recovering up to $250 million of transition costs if the rate of customers (excluding contracts and full-service accounts) switching their service from OE had not reached 20% for any consecutive twelve-month period by December 31, 2005 - the end of the market development period. Based on actual shopping levels through October 2002, OE has achieved its required 20% customer shopping and there is no longer risk of regulatory action reducing the recoverable transition costs. Significant Accounting Policies ------------------------------- OE prepares its 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 the OE Companies' financial results. All of the OE Companies' 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. The OE Companies' more significant accounting policies are described below. Regulatory Accounting The OE Companies are subject to regulation that sets the prices (rates) they are permitted to charge their customers based on the costs that regulatory agencies determine the OE Companies 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 - $2.1 billion as of September 30, 2002. OE regularly reviews 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. 38 Revenue Recognition The OE Companies follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the OE Companies periodically evaluate their 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 impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, the OE Companies recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and assumptions of future activities. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation. 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. In selecting an assumed discount rate, FirstEnergy considers fixed income security yields for AA rated corporate debt. Corporate bond yields, as well as interest rates in general, have declined in the first nine months of 2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If the discount rate is reduced below the current assumed rate, liabilities and pension and OPEB costs would increase in 2003. FirstEnergy's assumed rate of return on its pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2001, 2000 and 1999, plan assets have earned (5.5%), (0.3%) and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed assuming a 10.25% rate of return on plan assets, consistent with long-term historical returns produced by the plan's investment portfolio. If a lower rate of return were to be assumed in 2003, the OE Companies reported pension costs would increase. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is moderated due to smaller asset balances. However, medical cost trends have significantly increased and could affect future postretirement benefit costs. 39 As a result of the reduced market value of its pension plan assets (see Postretirement Plans), FirstEnergy could be required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits." The offset to the liability would be recorded as a reduction to common stockholder's equity through an after-tax charge to other comprehensive income (OCI), and would not affect net income for 2002. The charge to OCI would reverse in future periods to the extent the fair value of trust assets would exceed the accumulated benefit obligation. The amount of pension liability to be recorded as of December 31, 2002, will depend upon the discount rate and asset returns experienced in 2002 (and any resulting change in FirstEnergy's assumptions). Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- 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 as of January 1, 2003. SFAS 143 requires the fair value of a liability for an asset retirement obligation to 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, both resulting in a period expense. 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 various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the fourth quarter of 2002. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," 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 will be 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. 40
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ------------------------ 2002 2001 2002 2001 -------- -------- ---------- ---------- (In thousands) OPERATING REVENUES........................................ $538,879 $603,332 $1,426,730 $1,618,515 -------- -------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel................................................... 15,809 19,685 48,167 54,438 Purchased power........................................ 140,357 135,156 398,251 543,251 Nuclear operating costs................................ 56,893 27,236 167,095 105,865 Other operating costs.................................. 80,786 72,923 215,986 223,622 -------- -------- ---------- ---------- Total operation and maintenance expenses........... 293,845 255,000 829,499 927,176 Provision for depreciation and amortization............ 17,846 51,705 74,650 161,433 General taxes.......................................... 40,771 37,261 116,010 109,211 Income taxes........................................... 57,925 86,087 110,003 115,381 -------- -------- ---------- ---------- Total operating expenses and taxes................. 410,387 430,053 1,130,162 1,313,201 -------- -------- ---------- ---------- OPERATING INCOME.......................................... 128,492 173,279 296,568 305,314 OTHER INCOME.............................................. 5,562 3,991 14,159 9,549 -------- -------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES........................ 134,054 177,270 310,727 314,863 -------- -------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt............................. 44,441 47,717 136,808 144,319 Allowance for borrowed funds used during construction.. (1,155) (594) (2,651) (1,667) Other interest expense (credit)........................ 1,727 1,257 1,073 (818) Subsidiaries' preferred stock dividend requirements.... 2,250 -- 6,650 -- -------- -------- ---------- ---------- Net interest charges............................... 47,263 48,380 141,880 141,834 -------- -------- ---------- ---------- NET INCOME................................................ 86,791 128,890 168,847 173,029 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 3,149 6,316 14,459 19,438 -------- -------- ---------- ---------- EARNINGS ON COMMON STOCK.................................. $ 83,642 $122,574 $ 154,388 $ 153,591 ======== ======== ========== ========== The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.
41
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- -------------- (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $4,090,597 $4,071,134 Less-Accumulated provision for depreciation............................... 1,797,438 1,725,727 ---------- ---------- 2,293,159 2,345,407 ---------- ---------- Construction work in progress- Electric plant.......................................................... 119,454 66,266 Nuclear fuel............................................................ 32,055 21,712 ---------- ---------- 151,509 87,978 ---------- ---------- 2,444,668 2,433,385 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust................................................ 437,824 475,543 Nuclear plant decommissioning trusts...................................... 219,340 211,605 Long-term notes receivable from associated companies...................... 103,091 103,425 Other..................................................................... 20,856 24,611 ---------- ---------- 781,111 815,184 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 8,206 296 Receivables- Customers............................................................... 15,803 17,706 Associated companies.................................................... 57,704 75,113 Other (less accumulated provisions of $1,015,000 for uncollectible accounts at both dates)................................. 147,411 99,716 Notes receivable from associated companies................................ 544 415 Materials and supplies, at average cost- Owned................................................................... 18,319 20,230 Under consignment....................................................... 35,436 28,533 Other..................................................................... 3,489 31,634 ---------- ---------- 286,912 273,643 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 921,557 874,488 Goodwill.................................................................. 1,370,639 1,370,639 Other..................................................................... 97,833 88,767 ---------- ---------- 2,390,029 2,333,894 ---------- ---------- $5,902,720 $5,856,106 ========== ==========
42
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- -------------- (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: Common stockholder's equity- Common stock, without par value, authorized 105,000,000 shares - 79,590,689 shares outstanding......................................... $ 981,962 $ 931,962 Retained earnings....................................................... 304,369 150,183 ---------- ---------- Total common stockholder's equity................................... 1,286,331 1,082,145 Preferred stock- Not subject to mandatory redemption..................................... 96,404 141,475 Subject to mandatory redemption......................................... 5,049 6,288 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures......... 100,000 100,000 Long-term debt............................................................ 2,035,187 2,156,322 ---------- ---------- 3,522,971 3,486,230 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 316,806 526,630 Accounts payable- Associated companies.................................................... 104,949 81,463 Other................................................................... 10,084 30,332 Notes payable to associated companies..................................... 287,225 97,704 Accrued taxes............................................................. 167,899 129,830 Accrued interest.......................................................... 59,489 57,101 Other..................................................................... 37,990 60,664 ---------- ---------- 984,442 983,724 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 656,104 637,339 Accumulated deferred investment tax credits............................... 73,141 76,187 Nuclear plant decommissioning costs....................................... 228,533 220,798 Pensions and other postretirement benefits................................ 236,516 231,365 Other..................................................................... 201,013 220,463 ---------- ---------- 1,395,307 1,386,152 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... __________ __________ $5,902,720 $5,856,106 ========== ========== The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these balance sheets.
43
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ------------------------ 2002 2001 2002 2001 -------- -------- ---------- ---------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 86,791 $128,890 $ 168,847 $ 173,029 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 17,846 51,705 74,650 161,433 Nuclear fuel and lease amortization................ 5,037 7,627 15,821 21,741 Other amortization................................. (3,937) (3,111) (12,104) (10,783) Deferred income taxes, net......................... 6,812 (5,910) 19,912 (1,250) Investment tax credits, net........................ (1,015) (969) (3,046) (2,908) Receivables........................................ 3,274 (120,852) (28,383) (105,792) Materials and supplies............................. (1,786) (657) (4,992) 14,900 Accounts payable................................... (23,141) (49,155) 3,238 (95,336) Other.............................................. 23,518 100,047 9,930 6,278 -------- -------- ---------- ---------- Net cash provided from operating activities...... 113,399 107,615 243,873 161,312 -------- -------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... 77,505 -- 77,505 -- Short-term borrowings, net........................... 162,858 97,280 189,521 225,866 Equity contributions from parent..................... 50,000 -- 50,000 -- Redemptions and Repayments- Preferred stock...................................... 47,017 1,000 147,017 11,716 Long-term debt....................................... 309,189 17,735 309,379 47,639 Dividend Payments- Common stock......................................... -- 70,100 -- 175,900 Preferred stock...................................... 2,283 6,793 10,668 20,870 -------- -------- ---------- ---------- Net cash used for (provided from) financing activities 68,126 (1,652) 150,038 30,259 -------- -------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... 40,545 93,062 102,467 108,642 Loans to associated companies.......................... -- -- -- 11,117 Loan payments from associated companies................ -- -- (205) (188) Capital trust investments.............................. (10,325) -- (37,719) (16,279) Sale of assets to associated companies................. -- -- -- (11,117) Other.................................................. 7,137 8,700 21,382 33,990 -------- -------- ---------- ---------- Net cash used for investing activities........... 37,357 101,762 85,925 126,165 -------- -------- ---------- ---------- Net increase in cash and cash equivalents................. 7,916 7,505 7,910 4,888 Cash and cash equivalents at beginning of period ......... 290 238 296 2,855 -------- -------- ---------- ---------- Cash and cash equivalents at end of period................ $ 8,206 $ 7,743 $ 8,206 $ 7,743 ======== ======== ========== ========== The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.
44 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of The Cleveland Electric Illuminating Company: We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of September 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2002. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2002 45 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI provides regulated electric distribution services in portions of northern Ohio. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI continues to provide power directly to wholesale customers under previously negotiated contracts, as well as to alternative energy suppliers under its regulatory plan. CEI's regulatory plan itemizes, or unbundles, the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of CEI are provided by FES - an affiliated company. Results of Operations --------------------- Operating revenues decreased $64.5 million or 10.7% in the third quarter and $191.8 million or 11.8% in the first nine months of 2002, as compared to the same periods of 2001. Reduced operating revenues reflect the combined effects of a weak but recovering economy, shopping by Ohio customers for alternative energy providers, reduced sales to wholesale customers and weather. Kilowatt-hour sales to generation customers decreased by 13.2% in the third quarter and 25.3% in the first nine months of 2002, compared to the same periods last year, principally from customer choice in Ohio. Sales of electric generation by alternative suppliers as a percent of total sales in the CEI franchise area increased to 32.5% in the third quarter of 2002 from 17.4% in the same period last year. During the first nine months of 2002, CEI's share of electric generation sales in its franchise area decreased by 19.1 percentage points, compared to the same period of 2001. Despite higher distribution deliveries in the third quarter of 2002, compared to the same quarter of 2001, distribution revenues decreased $1.1 million - reflecting decreases in commercial and industrial revenues partially offset by an increase in kilowatt-hour sales to residential customers due to unusually hot summer weather. Distribution deliveries declined by 5.0% and revenues from electricity throughput decreased by $28.9 million in the first nine months of 2002, compared to the same period last year, primarily due to the weaker economic conditions earlier in the year. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, further reduced operating revenues in the third quarter and first nine months of 2002, compared to the corresponding periods of 2001 - reducing comparable revenues by $13.7 million and $37.8 million, respectively. These revenue reductions are deferred for future recovery under CEI's transition plan and do not materially affect current period earnings. Sales revenues to wholesale customers decreased by $20.6 million in the third quarter and $19.8 million in the year-to-date period of 2002, compared to the same periods last year, on lower kilowatt-hour sales in both periods. Reduced kilowatt-hour sales resulted principally from lower sales to FES reflecting the extended outage at Davis-Besse. The sources of changes in operating revenues during the third quarter and first nine months of 2002, compared with the corresponding periods of 2001, are summarized in the following table: Sources of Operating Revenue Changes ------------------------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Retail: Generation sales.................... $(24.5) $ (95.5) Distribution deliveries............. (1.1) (28.9) Increased shopping incentives....... (13.7) (37.8) ------ ------- Total Retail........................ (39.3) (162.2) Wholesale............................. (20.6) (19.8) Other................................. (4.6) (9.8) ------ ------- Net Decrease in Operating Revenue..... $(64.5) $(191.8) ====== ======= Operating Expenses and Taxes Total operating expenses and taxes declined $19.7 million in the third quarter and $183.0 million in the first nine months of 2002 from the corresponding periods of 2001. Purchased power costs increased $5.2 million in the third quarter compared to the same period last year, due to higher unit costs partially offset by reduced volume requirements supporting 46 lower generation kilowatt-hour sales. In the first nine months of 2002, purchased power costs decreased $145.0 million compared to the same period last year, due to lower unit costs and reduced volume requirements supporting lower generation kilowatt-hour sales. Nuclear operating costs increased $29.7 million in the third quarter and $61.2 million in the first nine months of 2002 from the same periods in 2001. Costs related to the extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration) resulted in higher nuclear costs in the third quarter of 2002 compared to the third quarter of 2001. In the first nine months of 2002, nuclear costs also included amounts incurred in the first quarter of 2002 for refueling outages at two nuclear plants (Beaver Valley Unit 2 and Davis-Besse), compared to only one refueling outage (Perry) in the first quarter of 2001. Other operating costs increased $7.9 million in the third quarter, compared to the same period last year, primarily due to employee severance costs and higher distribution expenses. During the first nine months of 2002, other operating costs decreased by $7.6 million as a result of lower outage-related fossil production costs and uncollectible account expenses, which were partially offset by employee severance costs and higher distribution expenses. Charges for depreciation and amortization decreased by $33.9 million in the third quarter and $86.8 million in the first nine months of 2002, compared to the same periods last year. These decreases reflect higher shopping incentive deferrals and tax-related deferrals under CEI's transition plan in 2002, the elimination of depreciation associated with the planned sale of the Ashtabula, Eastlake and Lakeshore generating plants (see Note 3), and the cessation of goodwill amortization beginning January 1, 2002, upon implementation of SFAS 142, "Goodwill and Other Intangible Assets." CEI's goodwill amortization in the third quarter and first nine months of 2001 totaled $9.6 million and $28.7 million, respectively. General taxes increased by $3.5 million in the third quarter and $6.8 million in the first nine months of 2002 from the same periods in 2001. Higher property taxes contributed to the increase in general taxes for both periods. Kilowatt-hour sales-related taxes on higher distribution deliveries also contributed to the increase in third quarter 2002. The increase in general taxes for the first nine months of 2002 was partially offset by reductions due to state tax changes in connection with the Ohio electric industry restructuring. Other Income A reduction in costs associated with the factoring of accounts receivable resulted in an increase in other income in the third quarter and first nine months of 2002, compared to the prior year - increasing other income by $1.6 million and $4.6 million, respectively. Preferred Stock Dividend Requirements Preferred stock dividend requirements decreased $3.2 million in the third quarter and $5.0 million in the first nine months of 2002, compared to the same periods last year, principally due to the completion of $146.0 million in optional preferred stock redemptions. Premiums related to the optional redemptions partially offset the lower dividend requirements. In the third quarter 2002, CEI received an equity contribution of $50 million that facilitated CEI's 2002 optional preferred stock redemptions. Capital Resources and Liquidity ------------------------------- CEI has continuing cash requirements for planned capital expenditures and maturing debt. During the last quarter of 2002, capital requirements for property additions are expected to be about $48 million, including $7 million for nuclear fuel. These capital requirements include the estimated incremental repair costs of the unplanned outage at the Davis-Besse nuclear plant discussed below. CEI also has sinking fund requirements for preferred stock of $17.8 million during the remainder of 2002. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. As of September 30, 2002, CEI had about $8.8 million of cash and temporary investments and $287.2 million of short-term indebtedness to associated companies. Under its first mortgage indenture, excluding property additions associated with the planned sale of coal-fired generating plants, CEI had the capability to issue up to $417 million of additional first mortgage bonds on the basis of property additions and retired bonds as of September 30, 2002. CEI has no restrictions on the issuance of preferred stock. Off-balance sheet debt equivalents for sale and leaseback transactions of generating units entered into in 1987 and accounts receivable factoring totaled $316 million as of September 30, 2002. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FirstEnergy 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. 47 Restart activities include both hardware and management issues. Of some 24,000 work activities identified for restarting Davis-Besse (refueling outages typically require 6,000 work activities) approximately 60% have been completed. 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. FirstEnergy expects to complete refurbishment and installation of the replacement reactor head as well as any other work related to restart of the plant early in 2003. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. The estimated costs (capital and expense) associated with the extended Davis-Besse outage (CEI's share - 51.38%) in 2002 and 2003 are: Costs of Davis-Besse Extended Outage ------------------------------------ Expenditure Range ----------------- (In millions) 2002 ---- Replace reactor vessel head (principally capital expenditures).. ........................................... $55 - $75 Primarily operating expenses (pre-tax): Additional maintenance (including acceleration of programs)... $115 - $135 Replacement power through September 2002...................... $85 Replacement power for October through December 2002........... $30 - $45 2003 ---- Additional work to enhance reliability and performance........ $50 The replacement power costs for 2003 are estimated to be $10-$15 million per month. Sales of Power Plants In November 2001, FirstEnergy announced an agreement to sell three of CEI's coal-fired power plants (see Note 3) 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 is reserving 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. FirstEnergy is pursuing opportunities with other parties who have expressed interest in purchasing the plants. It expects to conclude a bid process with interested parties in the fourth quarter of 2002, with the objective of executing an acceptable sales agreement by year-end. If FirstEnergy has not executed a sales agreement by year-end, CEI would need to reflect up to $37 million of previously unrecognized depreciation and other transaction costs related to these plants from November 2001 through September 2002 on its Consolidated Statement of Income. Postretirement Plans FirstEnergy maintains defined benefit pension plans, as well as several other postretirement employee benefit (OPEB) plans such as health care and life insurance. All of CEI's full-time employees are eligible to participate in these plans. In accordance with the provisions of the Employment Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded status of its pension plans annually to determine if additional funding is necessary. FirstEnergy has pre-funded a portion of the future liabilities related to its OPEB plans. Under the terms of its postretirement benefit plans, FirstEnergy reserves the right to change, modify or terminate the plans. Its pension plan funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA - no contributions have been required since 1985. Due to sharp declines in the equity markets in the United States since the second quarter of 2000, the value of assets held in the trusts to satisfy the obligations of pension plans has significantly decreased. As a result, under the minimum funding requirements of ERISA or the Pension Benefit Guaranty Corporation, FirstEnergy may be required to resume contributing to the plan trusts as early as 2004. FirstEnergy believes that it has adequate capital resources through cash generated from operations and through existing lines of credit to support necessary funding requirements based on anticipated plan performance. While OPEB plan assets have also been affected by the sharp declines in the equity market, contributions are voluntary and declines have a limited impact on required future funding. If the market value of FirstEnergy's pension plan assets were to remain unchanged from October 31, 2002, through the end of the year, CEI would be required to record an after-tax charge to equity (other comprehensive income) of approximately $8 million in the fourth quarter of 2002 to recognize its additional minimum pension liability of $21 million. The amount recorded will depend upon the financial markets and interest rates in the remainder of 2002. In addition, pension and other postretirement costs could increase by as much as $7 million are anticipated for 2003 based on the reduction of plan assets through October 31, 2002, due to lower rate of return assumptions and the amortization of unrecognized losses, 48 as well as higher health care trend rates for OPEB (see Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting). Environmental Matters --------------------- CEI has been named 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 September 30, 2002, based on estimates of the total costs of cleanup, CEI's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. CEI has accrued liabilities of approximately $2.8 million as of September 30, 2002, and does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Significant Accounting Policies ------------------------------- CEI prepares its 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 CEI's financial results. All of CEI's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. CEI's goodwill will be reviewed for impairment at least annually in accordance with SFAS 142. CEI's annual review was completed in the third quarter of 2002 - the results of that review indicated no impairment of goodwill. Other assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. CEI's more significant accounting policies are described below. Regulatory Accounting CEI is subject to regulation that sets the prices (rates) it is permitted to charge customers based on the costs that regulatory agencies determine CEI is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio, a significant amount of regulatory assets have been recorded - $922 million as of September 30, 2002. CEI regularly reviews 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 CEI follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," CEI periodically evaluates its 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 impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, CEI recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). 49 Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and assumptions of future activities. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation. 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. In selecting an assumed discount rate, FirstEnergy considers fixed income security yields for AA rated corporate debt. Corporate bond yields, as well as interest rates in general, have declined in the first nine months of 2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If the discount rate is reduced below the current assumed rate, liabilities and pension and OPEB costs would increase in 2003. FirstEnergy's assumed rate of return on its pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2001, 2000 and 1999, plan assets have earned (5.5%), (0.3%) and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed assuming a 10.25% rate of return on plan assets, consistent with long-term historical returns produced by the plan's investment portfolio. If a lower rate of return were to be assumed in 2003, CEI's reported pension costs would increase. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is moderated due to smaller asset balances. However, medical cost trends have significantly increased and could affect future postretirement benefit costs. As a result of the reduced market value of its pension plan assets (see Postretirement Plans), FirstEnergy could be required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits." The offset to the liability would be recorded as a reduction to common stockholder's equity through an after-tax charge to other comprehensive income (OCI), and would not affect net income for 2002. The charge to OCI would reverse in future periods to the extent the fair value of trust assets would exceed the accumulated benefit obligation. The amount of pension liability to be recorded as of December 31, 2002, will depend upon the discount rate and asset returns experienced in 2002 (and any resulting change in FirstEnergy's assumptions). Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- 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 as of January 1, 2003. SFAS 143 requires the fair value of a liability for an asset retirement obligation to 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, both resulting in a period expense. 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 various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the fourth quarter of 2002. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," 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 will be 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. 50
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) OPERATING REVENUES........................................ $269,857 $306,512 $764,331 $841,150 -------- -------- -------- -------- OPERATING EXPENSES AND TAXES: Fuel................................................... 9,524 13,671 30,342 38,439 Purchased power........................................ 85,329 137,679 247,085 312,744 Nuclear operating costs................................ 62,574 36,254 183,214 121,013 Other operating costs.................................. 43,627 38,259 114,426 114,172 -------- -------- -------- -------- Total operation and maintenance expenses........... 201,054 225,863 575,067 586,368 Provision for depreciation and amortization............ 23,413 30,818 64,529 92,833 General taxes.......................................... 14,061 13,256 41,258 43,196 Income taxes........................................... 6,287 8,951 14,618 29,440 -------- -------- -------- -------- Total operating expenses and taxes................. 244,815 278,888 695,472 751,837 -------- -------- -------- -------- OPERATING INCOME.......................................... 25,042 27,624 68,859 89,313 OTHER INCOME.............................................. 4,033 3,896 12,119 9,862 -------- -------- -------- -------- INCOME BEFORE NET INTEREST CHARGES........................ 29,075 31,520 80,978 99,175 -------- -------- -------- -------- NET INTEREST CHARGES: Interest on long-term debt............................. 14,611 16,494 46,084 50,354 Allowance for borrowed funds used during construction.. (611) (285) (1,421) (3,548) Other interest expense (credit)........................ 463 (1,117) (632) (3,228) -------- -------- -------- -------- Net interest charges............................... 14,463 15,092 44,031 43,578 -------- -------- -------- -------- NET INCOME................................................ 14,612 16,428 36,947 55,597 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,211 4,030 9,145 12,105 -------- -------- -------- -------- EARNINGS ON COMMON STOCK.................................. $ 12,401 $ 12,398 $ 27,802 $ 43,492 ======== ======== ======== ======== The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.
51
THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- ------------- (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $1,593,929 $1,578,943 Less-Accumulated provision for depreciation............................... 686,171 645,865 ---------- ---------- 907,758 933,078 ---------- ---------- Construction work in progress- Electric plant.......................................................... 79,868 40,220 Nuclear fuel............................................................ 27,751 19,854 ---------- ---------- 107,619 60,074 ---------- ---------- 1,015,377 993,152 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust................................................ 242,098 262,131 Nuclear plant decommissioning trusts...................................... 168,666 156,084 Long-term notes receivable from associated companies...................... 162,207 162,347 Other..................................................................... 3,395 4,248 ---------- ---------- 576,366 584,810 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 519 302 Receivables- Customers............................................................... 6,890 5,922 Associated companies.................................................... 46,463 64,667 Other................................................................... 3,326 9,709 Notes receivable from associated companies................................ 26,752 7,607 Materials and supplies, at average cost- Owned................................................................... 13,657 13,996 Under consignment....................................................... 21,359 17,050 Prepayments and other..................................................... 1,909 14,580 ---------- ---------- 120,875 133,833 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 397,629 388,846 Goodwill.................................................................. 445,732 445,732 Other..................................................................... 34,209 25,745 ---------- ---------- 877,570 860,323 ---------- ---------- $2,590,188 $2,572,118 ========== ==========
52
THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- ------------- (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: 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 Retained earnings....................................................... 135,638 113,436 ---------- ---------- Total common stockholder's equity................................... 759,867 637,665 Preferred stock not subject to mandatory redemption....................... 126,000 126,000 Long-term debt............................................................ 591,600 646,174 ---------- ---------- 1,477,467 1,409,839 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 135,830 347,593 Accounts payable- Associated companies.................................................... 95,076 53,960 Other................................................................... 6,847 27,418 Notes payable to associated companies..................................... 147,442 17,208 Accrued taxes............................................................. 52,542 39,848 Accrued interest.......................................................... 15,872 19,918 Other..................................................................... 34,309 40,222 ---------- ---------- 487,918 546,167 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 216,129 213,145 Accumulated deferred investment tax credits............................... 29,955 31,342 Nuclear plant decommissioning costs....................................... 175,008 162,426 Pensions and other postretirement benefits................................ 122,271 120,561 Other..................................................................... 81,440 88,638 ---------- ---------- 624,803 616,112 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $2,590,188 $2,572,118 ========== ========== The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets.
53
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ----------------------- ---------------------- 2002 2001 2002 2001 --------- -------- -------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 14,612 $ 16,428 $ 36,947 $ 55,597 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 23,413 30,818 64,529 92,833 Nuclear fuel and lease amortization................ 2,765 5,495 9,009 15,905 Deferred income taxes, net......................... (5,911) (4,966) (19) (1,814) Investment tax credits, net........................ (414) (490) (1,387) (1,463) Receivables........................................ 22,359 3,406 23,619 7,406 Materials and supplies............................. (2,150) (689) (3,970) 10,023 Accounts payable................................... 26,894 29,074 20,545 24,583 Accrued sale leaseback costs....................... 8,905 24,879 (19,549) (4,278) Other.............................................. 7,556 3,512 9,597 (15,885) --------- -------- -------- --------- Net cash provided from operating activities...... 98,029 107,467 139,321 182,907 --------- -------- -------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net........................... 13,279 -- 130,234 -- Equity contributions from parent..................... 100,000 -- 100,000 -- Redemptions and Repayments- Preferred stock...................................... -- -- 85,299 -- Long-term debt....................................... 167,705 1,961 179,968 33,773 Short-term borrowings, net........................... -- 7,491 -- 41,936 Dividend Payments- Common stock......................................... -- -- 5,600 14,700 Preferred stock...................................... 2,211 4,030 7,846 12,103 --------- -------- -------- --------- Net cash used for financing activities........... 56,637 13,482 48,479 102,512 --------- -------- -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... 26,636 54,670 66,897 75,179 Loans to associated companies.......................... 10,798 30,017 19,005 128,351 Capital trust investments.............................. (3,207) 57 (20,033) (17,648) Sale of assets to associated companies................. -- -- -- (123,438) Other.................................................. 7,099 6,933 24,756 16,679 --------- -------- -------- --------- Net cash used for investing activities........... 41,326 91,677 90,625 79,123 --------- -------- -------- --------- Net increase in cash and cash equivalents................. 66 2,308 217 1,272 Cash and cash equivalents at beginning of period.......... 453 349 302 1,385 --------- -------- -------- --------- Cash and cash equivalents at end of period................ $ 519 $ 2,657 $ 519 $ 2,657 ========= ======== ======== ========= The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.
54 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of The Toledo Edison Company: We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of September 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2002. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2002 55 THE TOLEDO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE provides regulated electric distribution services in portions of northern Ohio. TE also provides generation services to those customers electing to retain TE as their power supplier. TE continues to provide power directly to wholesale customers under previously negotiated contracts, as well as to alternative energy suppliers under its regulatory plan. TE's regulatory plan itemizes, or unbundles, the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of TE are provided by FES - an affiliated company. Results of Operations --------------------- Operating revenues decreased $36.7 million or 12.0% in the third quarter and $76.8 million or 9.1% in the first nine months of 2002, as compared to the same periods of 2001. Reduced operating revenues reflect the combined effects of a weak but recovering economy, shopping by Ohio customers for alternative energy providers, reduced sales to wholesale customers and weather. Kilowatt-hour sales to generation customers decreased by 11.3% in the third quarter and 11.6% in the first nine months of 2002, compared to the same periods last year, due principally to customer choice in Ohio. Sales of electric generation by alternative suppliers as a percent of total sales delivered in the TE franchise area increased to 19.4% in the third quarter of 2002 from 7.6% in the same period last year. During the first nine months of 2002, TE's share of electric generation sales in its franchise areas decreased by 11.6 percentage points, compared to the same period in 2001. Despite higher distribution deliveries in the third quarter and first nine months of 2002, compared to the same periods of 2001, distribution revenues decreased $5.0 million and $12.3 million, respectively, reflecting decreases in commercial and industrial revenues partially offset by an increase in kilowatt-hour sales to residential customers due to unusually hot summer weather. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, further magnified the effect of generation sales reductions to operating revenues in the third quarter and first nine months of 2002, compared to the corresponding periods of 2001 - reducing comparable revenues by $4.8 million and $12.5 million, respectively. These revenue reductions are deferred for future recovery under TE's transition plan and do not materially affect current period earnings. Sales revenues to wholesale customers decreased by $17.5 million in the third quarter and $27.0 million in the year-to-date period of 2002, compared to the same periods last year, on lower kilowatt-hour sales in both periods. Reduced kilowatt-hour sales resulted principally from lower sales to FES reflecting the extended outage at Davis-Besse. The sources of changes in operating revenues during the third quarter and first nine months of 2002, compared with the corresponding periods of 2001, are summarized in the following table: Sources of Operating Revenue Changes ------------------------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Retail: Generation sales....................... $ (8.5) $(23.5) Distribution deliveries................ (5.0) (12.3) Increased shopping incentives.......... (4.8) (12.5) ------ ------ Total Retail........................... (18.3) (48.3) Wholesale................................ (17.5) (27.0) Other.................................... ( 0.9) (1.5) ------ ------ Net Decrease in Operating Revenue........ $(36.7) $(76.8) ====== ====== 56 Operating Expenses and Taxes Total operating expenses and taxes declined by $34.1 million in the third quarter and $56.4 million in the first nine months of 2002 from the corresponding periods of 2001. Purchased power costs decreased $52.4 million and $65.7 million in the third quarter and first nine months of 2002, compared to the same periods last year, due to lower unit costs and reduced volume requirements supporting lower generation kilowatt-hour sales. Nuclear operating costs increased by $26.3 million in the third quarter and $62.2 million in the first nine months of 2002 from the same periods in 2001. Costs related to the extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration) resulted in higher nuclear costs in the third quarter of 2002 compared to the third quarter of last year. During the first nine months of 2002, costs also included amounts incurred in the first quarter of 2002 for refueling outages at two nuclear plants (Beaver Valley Unit 2 and Davis-Besse), compared to only one refueling outage (Perry) in the first quarter of 2001. Other operating costs increased $5.4 million in the third quarter of 2002, compared to the same period last year, in large part due to employee severance costs and higher distribution and uncollectible accounts expenses. Charges for depreciation and amortization decreased by $7.4 million in the third quarter and $28.3 million in the first nine months of 2002, compared to the same periods last year. These decreases reflect higher shopping incentive deferrals and tax-related deferrals under TE's transition plan in 2002, the elimination of depreciation associated with the planned sale of the Bay Shore generating plant (see Note 3) and the cessation of goodwill amortization beginning January 1, 2002, upon implementation of SFAS 142, "Goodwill and Other Intangible Assets." TE's goodwill amortization in the third quarter and first nine months of 2001 totaled $3.1 million and $9.3 million, respectively. General taxes decreased by $1.9 million in the first nine months of 2002, compared to the same period last year, due to state tax changes in connection with the Ohio electric industry restructuring. Capital Resources and Liquidity ------------------------------- TE has continuing cash requirements for planned capital expenditures and maturing debt. During the last quarter of 2002, capital requirements for property additions are expected to be about $33 million, including $3 million for nuclear fuel. These capital requirements include the estimated incremental repair costs of the unplanned outage at the Davis-Besse nuclear plant discussed below. TE also has sinking fund requirements for maturing long-term debt of $0.4 million during the remainder of 2002. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. As of September 30, 2002, TE had about $27.3 million of cash and temporary investments and $147.4 million of short-term indebtedness to associated companies. Under its first mortgage indenture, excluding property additions associated with the planned sale of the Bay Shore Plant, TE could not issue any additional first mortgage bonds as of September 30, 2002. Under the earnings coverage test contained in TE's charter, no preferred stock could be issued based on earnings through the third quarter of 2002. Off-balance sheet debt equivalents for sale and leaseback transactions of generating units entered into in 1987 totaled $654 million as of September 30, 2002. In the third quarter 2002, TE received an equity contribution of $100 million from FirstEnergy that facilitated TE's optional long-term debt and preferred stock redemptions. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FirstEnergy 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. Of some 24,000 work activities identified for restarting Davis-Besse (refueling outages typically require 6,000 work activities) approximately 60% have been completed. 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. FirstEnergy expects to complete refurbishment and installation of the replacement reactor head as well as any other work related to restart of the plant early in 2003. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. The estimated costs (capital and expense) associated with the extended Davis-Besse outage (TE share - 48.62%) in 2002 and 2003 are: 57 Costs of Davis-Besse Extended Outage ------------------------------------ Expenditure Range ----------------- (In millions) 2002 ---- Replace reactor vessel head (principally capital expenditures).. $55 - $75 Primarily operating expenses (pre-tax): Additional maintenance (including acceleration of programs)..... $115 - $135 Replacement power through September 2002........................ $85 Replacement power for October through December 2002............. $30 - $45 2003 ---- Additional work to enhance reliability and performance.......... $50 The replacement power costs for 2003 are estimated to be $10-$15 million per month. Sale of Bay Shore Power Plant In November 2001, FirstEnergy announced an agreement to sell TE's 648 megawatt Bay Shore Plant (see Note 3) 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 is reserving 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. FirstEnergy is pursuing opportunities with other parties who have expressed interest in purchasing the plants. It expects to conclude a bid process with interested parties in the fourth quarter of 2002, with the objective of executing an acceptable sales agreement by year-end. If FirstEnergy has not executed a sales agreement by year-end, TE would need to reflect up to $10 million of previously unrecognized depreciation and other transaction costs related to these plants from November 2001 through September 2002 on its Consolidated Statement of Income. Postretirement Plans FirstEnergy maintains defined benefit pension plans, as well as several other postretirement employee benefit (OPEB) plans such as health care and life insurance. All of TE's full-time employees are eligible to participate in these plans. In accordance with the provisions of the Employment Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded status of its pension plans annually to determine if additional funding is necessary. FirstEnergy has pre-funded a portion of the future liabilities related to its OPEB plans. Under the terms of its postretirement benefit plans, FirstEnergy reserves the right to change, modify or terminate the plans. Its pension plan funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA - no contributions have been required since 1985. Due to sharp declines in the equity markets in the United States since the second quarter of 2000, the value of assets held in the trusts to satisfy the obligations of pension plans has significantly decreased. As a result, under the minimum funding requirements of ERISA or the Pension Benefit Guaranty Corporation, FirstEnergy may be required to resume contributing to the plan trusts in 2004 or future years. FirstEnergy believes that it has adequate capital resources through cash generated from operations and through existing lines of credit to support necessary funding requirements based on anticipated plan performance. While OPEB plan assets have also been affected by the sharp declines in the equity market, contributions are voluntary and declines have a limited impact on required future funding. If the market value of FirstEnergy's pension plan assets were to remain unchanged from October 31, 2002, through the end of the year, TE would be required to record an after-tax charge to equity (other comprehensive income) of approximately $4 million in the fourth quarter of 2002 to recognize its additional minimum pension liability of $11 million. The amount recorded will depend upon the financial markets and interest rates in the remainder of 2002. In addition, pension and other postretirement costs could increase by as much as $4 million in 2003 based on the reduction of plan assets through October 31, 2002, due to adverse equity market conditions, lower rate of return assumptions and the amortization of unrecognized losses, as well as higher health care trend rates for OPEB (see Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting). Environmental Matters --------------------- TE has been named 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 September 30, 2002, based on estimates of the total costs of cleanup, TE's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. TE has accrued liabilities of approximately $0.2 million as of September 30, 2002, and does not 58 believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Significant Accounting Policies ------------------------------- TE prepares its 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 TE's financial results. All of TE's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. TE's goodwill will be reviewed for impairment at least annually in accordance with SFAS 142. FirstEnergy's annual review was completed in the third quarter of 2002 - the results of that review indicate no impairment of goodwill. Other assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. TE's more significant accounting policies are described below. Regulatory Accounting TE is subject to regulation that sets the prices (rates) it is permitted to charge customers based on the costs that regulatory agencies determine TE is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio, a significant amount of regulatory assets have been recorded - $398 million as of September 30, 2002. TE regularly reviews 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 TE follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," TE periodically evaluates its 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 impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, TE recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and assumptions of future activities. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation. 59 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. In selecting an assumed discount rate, FirstEnergy considers fixed income security yields for AA rated corporate debt. Corporate bond yields, as well as interest rates in general, have declined in the first nine months of 2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If the discount rate is reduced below the current assumed rate, liabilities and pension and OPEB costs would increase in 2003. FirstEnergy's assumed rate of return on its pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2001, 2000 and 1999, plan assets have earned (5.5%), (0.3%) and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed assuming a 10.25% rate of return on plan assets, consistent with long-term historical returns produced by the plan's investment portfolio. If a lower rate of return were to be assumed in 2003, TE's reported pension costs would increase. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is moderated due to smaller asset balances. However, medical cost trends have significantly increased and could affect future postretirement benefit costs. As a result of the reduced market value of its pension plan assets (see Postretirement Plans), FirstEnergy could be required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits." The offset to the liability would be recorded as a reduction to common stockholder's equity through an after-tax charge to other comprehensive income (OCI), and would not affect net income for 2002. The charge to OCI would reverse in future periods to the extent the fair value of trust assets would exceed the accumulated benefit obligation. The amount of pension liability to be recorded as of December 31, 2002, will depend upon the discount rate and asset returns experienced in 2002 (and any resulting change in FirstEnergy assumptions). Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- 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 as of January 1, 2003. SFAS 143 requires the fair value of a liability for an asset retirement obligation to 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, both resulting in a period expense. 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 various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the fourth quarter of 2002. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," 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 will be 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. 60
PENNSYLVANIA POWER COMPANY STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) OPERATING REVENUES........................................ $131,917 $121,349 $383,989 $374,447 -------- -------- -------- -------- OPERATING EXPENSES AND TAXES: Fuel................................................... 6,568 5,065 19,280 17,593 Purchased power........................................ 40,057 34,389 115,683 113,948 Nuclear operating costs................................ 19,155 47,316 60,960 86,833 Other operating costs.................................. 13,365 11,909 33,034 34,102 -------- -------- -------- -------- Total operation and maintenance expenses........... 79,145 98,679 228,957 252,476 Provision for depreciation and amortization............ 14,203 14,307 42,615 42,837 General taxes.......................................... 6,720 4,542 18,730 10,283 Income taxes........................................... 13,044 1,218 38,295 27,375 -------- -------- -------- -------- Total operating expenses and taxes................. 113,112 118,746 328,597 332,971 -------- -------- -------- -------- OPERATING INCOME.......................................... 18,805 2,603 55,392 41,476 OTHER INCOME.............................................. 739 959 1,880 2,581 -------- -------- -------- -------- INCOME BEFORE NET INTEREST CHARGES........................ 19,544 3,562 57,272 44,057 -------- -------- -------- -------- NET INTEREST CHARGES: Interest expense....................................... 4,188 4,527 12,554 13,929 Allowance for borrowed funds used during construction.. (447) (237) (1,044) (577) -------- -------- -------- -------- Net interest charges............................... 3,741 4,290 11,510 13,352 -------- -------- -------- -------- NET INCOME (LOSS)......................................... 15,803 (728) 45,762 30,705 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 926 926 2,778 2,778 -------- -------- -------- -------- EARNINGS (LOSS) APPLICABLE TO COMMON STOCK................ $ 14,877 $ (1,654) $ 42,984 $ 27,927 ======== ======== ======== ======== The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.
61
PENNSYLVANIA POWER COMPANY BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $674,694 $664,432 Less-Accumulated provision for depreciation............................... 308,799 290,216 -------- -------- 365,895 374,216 -------- -------- Construction work in progress- Electric plant.......................................................... 37,541 24,141 Nuclear fuel............................................................ 815 2,921 -------- -------- 38,356 27,062 -------- -------- 404,251 401,278 -------- -------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 118,339 116,634 Long-term notes receivable from associated companies...................... 39,015 39,290 Other..................................................................... 21,556 21,597 -------- -------- 178,910 177,521 -------- -------- CURRENT ASSETS: Cash and cash equivalents................................................. 1,454 67 Receivables- Customers (less accumulated provisions of $707,000 and $619,000, respectively, for uncollectible accounts)............................. 45,833 40,890 Associated companies.................................................... 35,330 36,491 Other................................................................... 4,649 4,787 Notes receivable from associated companies................................ 22,830 54,411 Materials and supplies, at average cost................................... 29,647 25,598 Prepayments............................................................... 9,579 5,682 -------- -------- 149,322 167,926 -------- -------- DEFERRED CHARGES: Regulatory assets......................................................... 170,362 208,838 Other..................................................................... 4,377 4,534 -------- -------- 174,739 213,372 -------- -------- $907,222 $960,097 ======== ========
62
PENNSYLVANIA POWER COMPANY BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- ------------ (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: Common stockholder's equity- Common stock, $30 par value, authorized 6,500,000 shares - 6,290,000 shares outstanding.......................................... $188,700 $188,700 Other paid-in capital................................................... (310) (310) Retained earnings....................................................... 49,882 35,398 -------- -------- Total common stockholder's equity................................... 238,272 223,788 Preferred stock- Not subject to mandatory redemption..................................... 39,105 39,105 Subject to mandatory redemption......................................... 14,250 14,250 Long-term debt- Associated companies.................................................... -- 21,064 Other................................................................... 185,978 240,983 -------- -------- 477,605 539,190 -------- -------- CURRENT LIABILITIES: Currently payable long-term debt- Associated companies.................................................... -- 18,090 Other................................................................... 66,572 12,075 Accounts payable- Associated companies.................................................... 32,139 50,604 Other................................................................... 1,161 1,441 Accrued taxes............................................................. 23,879 18,853 Accrued interest.......................................................... 3,484 5,264 Other..................................................................... 9,860 9,675 -------- -------- 137,095 116,002 -------- -------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 122,072 136,808 Accumulated deferred investment tax credits............................... 3,884 4,108 Nuclear plant decommissioning costs....................................... 118,801 117,096 Other..................................................................... 47,765 46,893 -------- -------- 292,522 304,905 -------- -------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... -------- -------- $907,222 $960,097 ======== ======== The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets.
63
PENNSYLVANIA POWER COMPANY STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ------------------------ --------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)......................................... $ 15,803 $ (728) $ 45,762 $ 30,705 Adjustments to reconcile net income (loss) to net cash from operating activities- Provision for depreciation and amortization.......... 14,203 14,307 42,615 42,837 Nuclear fuel and lease amortization.................. 5,054 3,733 14,622 12,974 Deferred income taxes, net........................... (1,731) (2,501) (5,606) (8,537) Investment tax credits, net.......................... (643) (688) (1,963) (2,098) Receivables.......................................... 376 16,469 (3,644) 17,783 Materials and supplies............................... (1,766) (159) (4,049) 6,149 Accounts payable..................................... 161 8,257 (18,745) (17,750) Accrued taxes........................................ (18,063) 6,758 5,026 10,127 Other................................................ 4,498 (2,738) (3,664) (11,354) -------- -------- -------- -------- Net cash provided from operating activities...... 17,892 42,710 70,354 80,836 -------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... 14,500 239 14,500 32,842 Redemptions and Repayments- Long-term debt....................................... 15,031 37,970 56,321 47,692 Dividend Payments- Common stock......................................... 20,700 21,100 28,500 27,400 Preferred stock...................................... 926 926 2,778 2,778 -------- -------- -------- -------- Net cash used for financing activities........... 22,157 59,757 73,099 45,028 -------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... 8,210 7,910 24,636 21,820 Loans to associated companies.......................... -- 10,245 -- 41,073 Loan payment from parent............................... (14,982) (3,870) (31,688) (17,510) Sale of assets to associated companies................. -- -- -- (6,053) Other.................................................. 1,643 319 2,920 (2,541) -------- -------- -------- -------- Net cash used for (provided from) investing activities ...................................... (5,129) 14,604 (4,132) 36,789 -------- -------- -------- -------- Net increase (decrease) in cash and cash equivalents...... 864 (31,651) 1,387 (981) Cash and cash equivalents at beginning of period.......... 590 34,145 67 3,475 -------- -------- -------- -------- Cash and cash equivalents at end of period................ $ 1,454 $ 2,494 $ 1,454 $ 2,494 ======== ======== ======== ======== The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.
64 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Pennsylvania Power Company: We have reviewed the accompanying balance sheet of Pennsylvania Power Company as of September 30, 2002, and the related statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2002. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2002 65 PENNSYLVANIA POWER COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Penn is a wholly owned electric utility subsidiary of OE. Penn provides regulated electric distribution services in western Pennsylvania. Penn also provides generation services to those customers electing to retain Penn as their power supplier. Penn provides power directly to wholesale customers under previously negotiated contracts. Penn's regulatory plan itemizes, or unbundles, the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Penn's power supply requirements are provided by FES - an affiliated company. Results of Operations --------------------- Operating revenues increased $10.6 million or 8.7% in the third quarter and $9.5 million or 2.5% in the first nine months of 2002, as compared to the same periods of 2001. Higher operating revenues in the third quarter of 2002 primarily resulted from warmer summer weather in 2002, compared to the same period in 2001. Operating revenues in the first nine months of 2002 also benefited from the return of generation customers previously served by alternative suppliers. During the first nine months of 2002, Penn's share of electric generation sales in its franchise area increased by 4.7 percentage points, compared to the same period in 2001. Distribution deliveries increased by 8.0% in the third quarter and 2.3% in the first nine months of 2002, compared to the same periods last year, increasing revenues from electricity throughput by $3.2 million and $2.9 million, respectively. Residential sales, which benefited from unusually hot summer weather, increased in both periods. Sales to commercial and industrial customers contributed to the third quarter increase but partially offset the increase in residential sales in the nine-month period due to the weaker economic environment earlier in the year. Sales to wholesale customers were also higher in the third quarter of 2002, compared to the same period last year. During the first nine months of 2002, lower wholesale revenues partially offset higher generation and distribution revenues. Reduced sales revenues from FES accounted for nearly all of the decrease in wholesale revenues in the year to date period. The sources of changes in operating revenues during the third quarter and first nine months of 2002, compared with the corresponding periods of 2001, are summarized in the following table: Sources of Operating Revenue Changes ------------------------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Retail: Generation sales...................... $ 3.2 $13.1 Distribution deliveries............... 3.2 2.9 ----- ----- Total Retail.......................... 6.4 16.0 Wholesale............................... 3.8 (7.9) Other................................... 0.4 1.4 ----- ----- Net Increase in Operating Revenue....... $10.6 $ 9.5 ===== ===== Operating Expenses and Taxes Total operating expenses and taxes decreased by $5.6 million in the third quarter and $4.4 million in the first nine months of 2002 from the corresponding periods of 2001. Purchased power costs increased $5.7 million in the third quarter of 2002 from the same quarter last year as a result of higher volume requirements and increased unit costs. During the first nine months, purchased power costs increased $1.7 million from 2001, primarily attributable to higher volume requirements more than offsetting lower unit costs. Nuclear operating costs decreased $28.2 million in the third quarter of 2002, compared to the corresponding period last year, primarily due to the absence of a refueling outage in the third quarter of 2002; Beaver Valley Unit 1 (65% owned) experienced a refueling outage in the third quarter of 2001. In the first nine months of 2002, nuclear operating costs decreased $25.9 million from the same period last year as a result of costs associated with two refueling outages in 2001 compared to only one refueling outage in 2002. 66 General taxes increased by $2.2 million in the third quarter and $8.4 million in the first nine months of 2002 from the same periods in 2001. An increase in the gross receipts tax rate for 2002 contributed to the increase in general taxes for both periods. The successful resolution of certain property tax issues in the second quarter of 2001 provided a one-time benefit of $3.0 million in that year. Capital Resources and Liquidity ------------------------------- Penn has continuing cash requirements for planned capital expenditures and maturing debt. During the fourth quarter of 2002, capital requirements for property additions and capital leases are expected to be about $21 million, including $8 million for nuclear fuel. Penn also has sinking fund requirements for preferred stock and maturing long-term debt of $1.2 million during the remainder of 2002. These requirements are expected to be satisfied from internal cash and/or short-term credit arrangements. As of September 30, 2002, Penn had about $24.3 million of cash and temporary investments and no short-term indebtedness. Under its first mortgage indenture, as of September 30, 2002, Penn had the capability to issue up to $310 million of additional first mortgage bonds on the basis of property additions and retired bonds. Under the earnings coverage test contained in Penn's charter, $317 million of preferred stock (assuming no additional debt was issued) could be issued based on earnings through the third quarter of 2002. Postretirement Plans FirstEnergy maintains defined benefit pension plans, as well as several other postretirement employee benefit (OPEB) plans such as health care and life insurance. All of Penn's full-time employees are eligible to participate in these plans. In accordance with the provisions of the Employment Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded status of its pension plans annually to determine if additional funding is necessary. FirstEnergy has pre-funded a portion of the future liabilities related to its OPEB plans. Under the terms of its postretirement benefit plans, FirstEnergy reserves the right to change, modify or terminate the plans. Its pension plan funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA - no contributions have been required since 1985. Due to sharp declines in the equity markets in the United States since the second quarter of 2000, the value of assets held in the trusts to satisfy the obligations of pension plans has significantly decreased. As a result, under the minimum funding requirements of ERISA or the Pension Benefit Guaranty Corporation, FirstEnergy may be required to resume contributing to the plan trusts as early as 2004. FirstEnergy believes that it has adequate access to capital resources through cash generated from operations and through existing lines of credit to support necessary funding requirements based on anticipated plan performance. While OPEB plan assets have also been affected by the sharp declines in the equity market, contributions are voluntary and declines have a limited impact on required future funding. If the market value of FirstEnergy's pension plan assets were to remain unchanged from October 31, 2002, through the end of the year, Penn would be required to record an after-tax charge to equity (other comprehensive income) of approximately $12 million in the fourth quarter of 2002 to recognize its additional minimum pension liability of $22 million. The amount recorded will depend upon the financial markets and interest rates in the remainder of 2002. In addition, pension and other postretirement costs could increase by as much as $2 million in 2003 based on the reduction of plan assets through October 31, 2002, lower rate of return assumptions and the amortization of unrecognized losses, as well as higher health care trend rates for OPEB (see Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting). Significant Accounting Policies ------------------------------- Penn prepares its 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 Penn's financial results. All of Penn's 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. Penn's more significant accounting policies are described below. Regulatory Accounting Penn is subject to regulation that sets the prices (rates) it is permitted to charge customers based on the costs that regulatory agencies determine Penn is 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 - $170 million as of September 30, 2002. Penn regularly reviews 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. 67 Revenue Recognition Penn follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," Penn periodically evaluates its 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 an impairment other than of a temporary nature has occurred, Penn would be required to recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and assumptions of future activities. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation. 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. In selecting an assumed discount rate, FirstEnergy considers fixed income security yields for AA rated corporate debt. Corporate bond yields, as well as interest rates in general, have declined in the first nine months of 2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If the discount rate is reduced below the current assumed rate, liabilities and pension and OPEB costs would increase in 2003. FirstEnergy's assumed rate of return on its pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2001, 2000 and 1999, plan assets have earned (5.5%), (0.3%) and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed assuming a 10.25% rate of return on plan assets, consistent with long-term historical returns produced by the plan's investment portfolio. If a lower rate of return were to be assumed in 2003, Penn's reported pension costs would increase. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is moderated due to smaller asset balances. However, medical cost trends have significantly increased and could affect future postretirement benefit costs. As a result of the reduced market value of its pension plan assets (see Postretirement Plans), FirstEnergy could be required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits." The offset to the liability would be recorded as a reduction to common 68 stockholder's equity through an after-tax charge to other comprehensive income (OCI), and would not affect net income for 2002. The charge to OCI would reverse in future periods to the extent the fair value of trust assets would exceed the accumulated benefit obligation. The amount of pension liability to be recorded as of December 31, 2002, will depend upon the discount rate and asset returns experienced in 2002 (and any resulting change in FirstEnergy's assumptions). Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- 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 as of January 1, 2003. SFAS 143 requires the fair value of a liability for an asset retirement obligation to 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, both resulting in a period expense. 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 various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the fourth quarter of 2002. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time these costs 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 will be 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. 69
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ----------------------- ----------------------- 2002 2001 2002 2001 -------- -------- ---------- ---------- (In thousands) OPERATING REVENUES........................................ $779,955 | $672,131 $1,731,900 | $1,654,867 -------- | -------- ---------- | ---------- | | OPERATING EXPENSES AND TAXES: | | Fuel................................................... 1,873 | 1,584 4,347 | 4,362 Purchased power........................................ 453,081 | 354,704 913,532 | 845,997 Other operating costs.................................. 50,587 | 59,815 193,204 | 191,271 -------- | -------- ---------- | ---------- Total operation and maintenance expenses........... 505,541 | 416,103 1,111,083 | 1,041,630 Provision for depreciation and amortization............ 67,645 | 62,272 186,919 | 186,705 General taxes.......................................... 17,740 | 18,295 39,037 | 48,949 Income taxes........................................... 67,689 | 57,296 134,093 | 116,627 -------- | -------- ---------- | ---------- Total operating expenses and taxes................. 658,615 | 553,966 1,471,132 | 1,393,911 -------- | -------- ---------- | ---------- | | OPERATING INCOME.......................................... 121,340 | 118,165 260,768 | 260,956 | | | | OTHER INCOME (EXPENSE).................................... 1,269 | (2,756) 6,291 | 803 -------- | -------- ---------- | ---------- | | | | INCOME BEFORE NET INTEREST CHARGES........................ 122,609 | 115,409 267,059 | 261,759 -------- | -------- ---------- | ---------- | | NET INTEREST CHARGES: | | Interest on long-term debt............................. 23,721 | 23,724 69,206 | 67,754 Allowance for borrowed funds used during construction.. (301) | 170 (880)| (261) Deferred interest...................................... (3,722) | (4,585) (5,107)| (10,991) Other interest expense (credit)........................ (538) | 2,279 (2,315)| 8,650 Subsidiaries' preferred stock dividend requirements.... 2,674 | 2,675 8,021 | 8,025 -------- | -------- ---------- | ---------- Net interest charges............................... 21,834 | 24,263 68,925 | 73,177 -------- | -------- ---------- | ---------- | | | | NET INCOME................................................ 100,775 | 91,146 198,134 | 188,582 | | PREFERRED STOCK DIVIDEND REQUIREMENTS..................... (2,773) | 1,299 (1,589)| 4,081 -------- | -------- ---------- | ---------- | | EARNINGS ON COMMON STOCK.................................. $103,548 | $ 89,847 $ 199,723 | 184,501 ======== | ======== ========== | ========== The preceding Notes to Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $3,519,541 $3,431,823 Less-Accumulated provision for depreciation............................... 1,397,661 1,313,259 ---------- ---------- 2,121,880 2,118,564 Construction work in progress- Electric plant.......................................................... 36,032 60,482 ---------- ---------- 2,157,912 2,179,046 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 106,782 114,899 Nuclear fuel disposal trust............................................... 146,809 137,098 Long-term notes receivable from associated companies...................... 20,333 20,333 Other..................................................................... 15,012 6,643 ---------- ---------- 288,936 278,973 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 61,592 31,424 Receivables- Customers (less accumulated provisions of $11,799,000 and $12,923,000, respectively, for uncollectible accounts)............................. 236,882 226,392 Associated companies.................................................... 301 6,412 Other................................................................... 20,998 20,729 Materials and supplies, at average cost................................... 1,304 1,348 Prepayments and other..................................................... 55,137 16,569 ---------- ---------- 376,214 302,874 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 3,204,360 3,324,804 Goodwill.................................................................. 1,944,164 1,926,526 Other..................................................................... 20,806 27,775 ---------- ---------- 5,169,330 5,279,105 ---------- ---------- $7,992,392 $8,039,998 ========== ==========
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JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- ------------ (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: Common stockholder's equity- Common stock, par value $10 per share, authorized 16,000,000 shares - 15,371,270 shares outstanding......................................... $ 153,713 $ 153,713 Other paid-in capital................................................... 2,992,374 2,981,117 Accumulated other comprehensive loss.................................... (828) (472) Retained earnings....................................................... 105,366 29,343 ---------- ---------- Total common stockholder's equity................................... 3,250,625 3,163,701 Preferred stock- Not subject to mandatory redemption..................................... 12,649 12,649 Subject to mandatory redemption......................................... -- 44,868 Company-obligated mandatorily redeemable preferred securities............. 125,246 125,250 Long-term debt............................................................ 1,216,989 1,224,001 ---------- ---------- 4,605,509 4,570,469 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 169,414 60,848 Accounts payable- Associated companies.................................................... 165,611 171,168 Other................................................................... 106,990 89,739 Notes payable to associated companies..................................... -- 18,149 Accrued taxes............................................................. 15,084 35,783 Accrued interest.......................................................... 32,596 25,536 Other..................................................................... 138,630 79,589 ---------- ---------- 628,325 480,812 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 613,112 514,216 Accumulated deferred investment tax credits............................... 10,792 13,490 Power purchase contract loss liability.................................... 1,712,144 1,968,823 Nuclear fuel disposal costs............................................... 165,543 163,377 Nuclear plant decommissioning costs....................................... 139,356 137,424 Other..................................................................... 117,611 191,387 ---------- ---------- 2,758,558 2,988,717 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- --------- $7,992,392 $8,039,998 ========== ========== The preceding Notes to Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these balance sheets.
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JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ----------------------- ----------------------- 2002 2001 2002 2001 --------- --------- --------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: | | Net income................................................ $ 100,775 | $ 91,146 $ 198,134 | $ 188,582 Adjustments to reconcile net income to net | | cash from operating activities- | | Provision for depreciation and amortization........ 67,645 | 62,272 186,919 | 186,705 Other amortization................................. (828) | 2,995 623 | 21,585 Deferred costs, net................................ (122,338) | (189,228) (231,286) | (303,102) Deferred income taxes, net......................... 48,583 | 50,305 85,123 | 70,223 Investment tax credits, net........................ (899) | (899) (2,698) | (2,698) Receivables........................................ (14,584) | 44,869 (4,647) | (60,517) Materials and supplies............................. (1) | 1 44 | (842) Accounts payable................................... (21,250) | (20,049) 11,694 | (50,080) Prepayments........................................ 41,706 | 39,247 (28,944) | 65,712 Accrued taxes...................................... 7,761 | 20,984 (20,699) | 54,285 Other.............................................. (10,132) | 2,626 (8,641) | (14,624) --------- | --------- --------- | --------- Net cash provided from operating activities...... 96,438 | 104,269 185,622 | 155,229 --------- | --------- --------- | --------- | | CASH FLOWS FROM FINANCING ACTIVITIES: | | New Financing- | | Long-term debt....................................... -- | -- 318,106 | 148,796 Redemptions and Repayments- | | Preferred stock...................................... 46,500 | 8,333 51,500 | 10,833 Long-term debt....................................... 146,033 | -- 196,033 | -- Short-term borrowings, net........................... -- | 106,000 18,149 | 29,200 Dividend Payments- | | Common stock......................................... 57,700 | -- 123,700 | 75,000 Preferred stock...................................... 256 | 1,299 2,000 | 4,081 --------- | --------- --------- | --------- Net cash used for (provided from) financing | | activities ..................................... 250,489 | 115,632 73,276 | (29,682) --------- | --------- --------- | --------- | | CASH FLOWS FROM INVESTING ACTIVITIES: | | Property additions..................................... 23,567 | 30,921 70,401 | 109,006 Decommissioning trust investments...................... 304 | 304 1,013 | 902 Other.................................................. 7,782 | (469) 10,764 | 2,852 --------- | --------- --------- | --------- Net cash used for investing activities........... 31,653 | 30,756 82,178 | 112,760 --------- | --------- --------- | --------- | | Net increase (decrease) in cash and cash equivalents...... (185,704) | (42,119) 30,168 | 72,151 Cash and cash equivalents at beginning of period.......... 247,296 | 116,291 31,424 | 2,021 --------- | --------- --------- | --------- Cash and cash equivalents at end of period................ $ 61,592 | $ 74,172 $ 61,592 | $ 74,172 ========= | ========= ========= | ========= The preceding Notes to Financial Statements as they relate to Jersey Power & Light Company are an integral part of these statements.
73 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Jersey Central Power & Light Company: We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of September 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2002. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2002 74 JERSEY CENTRAL POWER & LIGHT COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION JCP&L is a wholly owned electric utility subsidiary of FirstEnergy. JCP&L conducts business in northern, western and east central New Jersey, offering regulated electric transmission and distribution services. JCP&L also provides power to those customers electing to retain them as their power supplier. JCP&L's regulatory plan itemizes, or unbundles, the price of electricity into its component elements - including generation, transmission, distribution and transition charges. JCP&L was formerly a wholly owned subsidiary of GPU, Inc., which merged with FirstEnergy on November 7, 2001. Results of Operations --------------------- Operating revenues increased by $107.8 million or 16.0% in the third quarter of 2002, and $77.0 million or 4.7% in the first nine months of 2002, compared to the same periods in 2001. The sources of the changes in operating revenues, as compared to the same periods in 2001, are summarized in the following table.
Sources of Operating Revenue Changes ------------------------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Change in kilowatt-hour sales due to level of retail customers shopping for generation service......... $ 0.4 $43.5 Change in other retail kilowatt-hour sales........... 41.3 3.0 Change in wholesale sales............................ 55.3 16.4 All other changes.................................... 10.8 14.1 ------ ----- Net Increase in Operating Revenues................... $107.8 $77.0 ====== =====
Electric Sales In the first nine months of 2002, a reduction in the number of customers who received their power from alternate suppliers continued to have a positive effect on operating revenues. During the first nine months of 2001, 5.7% of kilowatt-hours delivered were to shopping customers, whereas only 0.6% of kilowatt-hours delivered during the same period in 2002 were to shopping customers. In addition to this increase in revenues from returning shopping customers, warmer weather in the third quarter of 2002 contributed to an increase in retail distribution deliveries. JCP&L also experienced a significant increase in sales to wholesale customers during the first nine months of 2002. A decline in economic conditions resulted in a slight decrease in sales to industrial customers for the nine months ended September 30, 2002; however, economic conditions continued to improve during the third quarter of 2002, resulting in an increase in industrial sales during that period. Changes in kilowatt-hour deliveries by customer class during the three and nine month periods ended September 30, 2002, as compared to the same periods in 2001, are summarized in the following table: Changes in Distribution Deliveries and Wholesale Generation Sales ------------------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Residential........................... 16.2% 5.3% Commercial............................ 6.9% 2.8% Industrial............................ 4.3% (0.4)% ----- ---- Total Retail..................... 10.8% 3.4% Wholesale............................. 174.5% 63.3% ----- ---- Total................................. 33.9% 9.5% ===== ==== 75 Operating Expenses and Taxes Total operating expenses and taxes increased $104.6 million in the third quarter of 2002, and $77.2 million in the first nine months of 2002, compared to the same periods in 2001. Purchased power costs increased $98.4 million and $67.5 million for the three and nine month periods ended September 30, 2002, respectively, compared to the same periods in 2001, as a result of additional power required and higher unit costs. A decrease in other operating costs of $9.2 million in the third quarter of 2002, compared to the same period in 2001, was primarily attributable to the absence of employee severance and retention costs in 2001, and lower accrued vacation expense and the deferral of uncollectible expenses under a new tariff rider. An increase in other operating costs of $1.9 million in the first nine months of 2002, compared to the same period in 2001, was primarily due to increased pension and other employee benefit costs, offset by the decreases discussed for the third quarter. Depreciation and amortization expenses increased $5.4 million for the quarter ended September 30, 2002, compared to the same period in 2001. The increase was primarily attributed to amortization associated with the bondable transition property transferred to JCP&L Transition Funding LLC in the second quarter of 2002, as well as higher depreciation due to higher average depreciable plant balances in the quarter ended September 30, 2002 versus the same period in 2001. These increases were partially offset by the cessation of amortization of regulatory assets related to the net investment in the previously divested Oyster Creek Nuclear Generating Station. General taxes decreased $9.9 million in the first nine months of 2002, compared to the same period in 2001, due principally to a reduction in the transitional energy facilities assessment during the second quarter of 2002. Other Income Other income increased $4.0 million in the third quarter of 2002, and $5.5 million in the first nine months of 2002, compared to the same periods in 2001, primarily due to the absence in 2002 of net losses incurred in 2001 on futures contracts and options. Net Interest Charges Net interest charges decreased $2.4 million in the third quarter of 2002, and $4.3 million in the first nine months of 2002, compared to the same periods in 2001, primarily due to reduced short-term borrowing levels and the amortization of fair value adjustments recognized in connection with the merger. Net interest charges were also affected by the issuance of $150 million of notes in May 2001, and $320 million of transition bonds by a special purpose finance subsidiary in June 2002, as well as the redemption of $40 million of notes in November 2001, $50 million of notes in March 2002 and $142 million of notes in July 2002. These transactions had an offsetting effect on net interest charges for the quarter ended September 30, 2002, and resulted in a $1.5 million increase in net interest charges for the nine months ended September 30, 2002. Preferred Stock Dividend Requirements Preferred stock dividend requirements decreased $4.1 million in the third quarter of 2002, and $5.7 million in the first nine months of 2002, compared to the same periods in 2001, primarily due to the recognition of a $2.9 million gain on the reacquisition of $29.8 million of preferred stock in the third quarter of 2002, and lower preferred stock dividends. Capital Resources and Liquidity ------------------------------- JCP&L has continuing cash requirements for planned capital expenditures, which are expected to be about $41.0 million during the remaining three months of 2002. These requirements are expected to be satisfied from internal cash and/or short-term credit arrangements. As of September 30, 2002, JCP&L had about $61.6 million of cash and temporary investments, and no short-term indebtedness. JCP&L may borrow from its affiliates on a short-term basis. JCP&L will not issue first mortgage bonds (FMBs) other than as collateral for senior notes, since its senior note indenture prohibits (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of September 30, 2002, JCP&L had the capability to issue up to $357.5 million of additional FMBs on the basis of retired bonds. Based upon applicable earnings coverage tests and its charter, JCP&L could issue $303.1 million of preferred stock (assuming no additional debt was issued) based on earnings through September 30, 2002. 76 Postretirement Plans FirstEnergy maintains defined benefit pension plans, as well as several other postretirement employee benefit (OPEB) plans such as health care and life insurance. All of JCP&L's full-time employees are eligible to participate in these plans. In accordance with the provisions of the Employment Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded status of its pension plans annually to determine if additional funding is necessary. FirstEnergy has pre-funded a portion of the future liabilities related to its OPEB plans. Under the terms of its postretirement benefit plans, FirstEnergy reserves the right to change, modify or terminate the plans. Its pension plan funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA - no contributions have been required since 1985. Due to sharp declines in the equity markets in the United States since the second quarter of 2000, the value of assets held in the trusts to satisfy the obligations of pension plans has significantly decreased. As a result, under the minimum funding requirements of ERISA or the Pension Benefit Guaranty Corporation, FirstEnergy may be required to resume contributing to the plan trusts as early as 2004. FirstEnergy believes that it has adequate access to capital resources through cash generated from operations and through existing lines of credit to support necessary funding requirements based on anticipated plan performance. While OPEB plan assets have also been affected by the sharp declines in the equity market, contributions are voluntary and declines have a limited impact on required future funding. If the market value of FirstEnergy's pension plan assets were to remain unchanged from October 31, 2002, through the end of the year, JCP&L would be required to record an after-tax charge to equity (other comprehensive income) of approximately $27 million in the fourth quarter of 2002 to recognize its additional minimum pension liability of $46 million. The amount recorded will depend upon the financial markets and interest rates in the remainder of 2002. In addition, pension and other postretirement costs could increase by as much as $30 million in 2003 based on the reduction of plan assets through October 31, 2002, due to adverse equity market conditions, lower rate of return assumptions and the amortization of unrecognized losses, as well as higher health care trend rates for OPEB (see Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting). Market Risk Information ----------------------- JCP&L uses various market sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. JCP&L's Risk Policy Committee, comprised of FirstEnergy executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk JCP&L is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, JCP&L uses a variety of derivative instruments, including forward contracts, options and futures contracts. The derivatives are used for hedging purposes. The change in the fair value of commodity derivative contracts related to energy production during the third quarter of 2002 is summarized in the following table: Change in the Fair Value of Commodity Derivative Contracts ---------------------------------------------------------- (In millions) Outstanding net asset as of June 30, 2002.............. $ 6.1 Increase in value of existing contracts................ 1.0 Change in techniques/assumptions....................... -- Settled contracts...................................... (0.4) ----- Outstanding net asset as of September 30, 2002......... $ 6.7 ===== 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, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L utilizes these results in developing estimates of fair value for the later years of applicable electricity contracts for both 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: 77 Source of Information - Fair Value by Contract Year --------------------------------------------------- 2002* 2003 2004 Thereafter Total ----- ---- ---- ---------- ----- (In millions) Prices actively quoted...... $-- $-- $-- $ -- $ -- Prices based on models**.... -- -- -- 6.7 6.7 --- --- --- ---- ---- Total..................... $-- $-- $-- $6.7 $6.7 === === === ==== ==== * For the last quarter of 2002. ** Relates to an embedded option that is offset by a regulatory liability and does not affect earnings. JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on JCP&L's consolidated financial position or cash flows as of September 30, 2002. New Jersey Regulatory Matters ----------------------------- On August 1, 2002, JCP&L submitted two rate filings with the New Jersey Board of Public Utilities (NJBPU). The first filing is a request to increase base electric rates by $98 million annually, an average of 5%. The second filing is a request to recover deferred costs associated with mandated purchase-power contracts with non-utility generators and providing Basic Generation Service to customers in excess of the state's generation rate cap. As of September 30, 2002, the accumulated deferred cost balance totaled approximately $482 million. The deferral filing would result in an additional 2.8% increase in rates, assuming the use of securitization. The securitization methodology is similar to the Oyster Creek securitization completed in May 2002. The NJBPU has directed the Office of Administrative Law to have its Administrative Law Judge issue a recommended decision by May 1, 2003; the Judge has indicated she would request an extension. The rates established in this proceeding will become effective August 1, 2003. Environmental Matters --------------------- JCP&L 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 September 30, 2002, based on estimates of the total costs of cleanup, JCP&L's 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 through the Societal Benefits Charge. JCP&L has accrued liabilities aggregating approximately $50.7 million as of September 30, 2002. JCP&L does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Significant Accounting Policies ------------------------------- JCP&L prepares its 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 JCP&L's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. JCP&L's goodwill will be reviewed for impairment at least annually in accordance with SFAS 142. JCP&L's annual review was completed in the third quarter of 2002 - the results of that review indicated no impairment of goodwill. Other assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Purchase Accounting - Acquisition of GPU On November 7, 2001, the merger between FirstEnergy and GPU became effective, and JCP&L became a wholly owned subsidiary of FirstEnergy. The merger was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities were based primarily on estimates. The adjustments reflected in JCP&L's records, which are subject to adjustment in 2002 when finalized, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over 78 the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill, which totaled $1.9 billion at September 30, 2002. Regulatory Accounting JCP&L is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine JCP&L is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in New Jersey, a significant amount of regulatory assets have been recorded - $3.2 billion as of September 30, 2002. JCP&L regularly reviews 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. JCP&L continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, JCP&L enters into commodity contracts, which increase the impact of derivative accounting judgments. Revenue Recognition JCP&L follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," JCP&L periodically evaluates its 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 impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, JCP&L recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and assumptions of future activities. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation. 79 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. In selecting an assumed discount rate, FirstEnergy considers fixed income security yields for AA rated corporate debt. Corporate bond yields, as well as interest rates in general, have declined in the first nine months of 2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If the discount rate is reduced from the current assumed rate, pension and OPEB liabilities and costs would increase in 2003. FirstEnergy's assumed rate of return on its pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2001, 2000 and 1999, return on plan assets has been (5.5%), (0.3%) and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed assuming a 10.25% rate of return on plan assets, consistent with long-term historical returns produced by the plan's investment portfolio. If a lower rate of return were to be assumed in 2003, JCP&L's reported pension costs would increase. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is moderated due to smaller asset balances. However, medical cost trends have significantly increased which could affect future postretirement benefit costs. As a result of the reduced market value of its pension plan assets (see Postretirement Plans), FirstEnergy could be required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits." The offset to the liability would be recorded as a reduction to common stockholder's equity through an after-tax charge to other comprehensive income (OCI), and would not affect net income for 2002. The charge to OCI would reverse in future periods if the fair value of trust assets exceeds the accumulated benefit obligation. The amount of pension liability to be recorded as of December 31, 2002 will depend upon the assumed discount rate (and any other change in FirstEnergy's assumptions) and actual asset returns experienced in 2002. Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- 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 as of January 1, 2003. SFAS 143 requires the fair value of a liability for an asset retirement obligation to 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, both resulting in a period expense. 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 various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the fourth quarter of 2002. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," 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 will be 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. 80
METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) OPERATING REVENUES........................................ $281,540 | $283,519 $767,333 | $727,075 -------- | -------- -------- | -------- | | OPERATING EXPENSES AND TAXES: | | Purchased power........................................ 201,320 | 164,313 483,756 | 417,915 Other operating costs.................................. 24,372 | 33,144 86,947 | 99,984 -------- | -------- -------- | -------- Total operation and maintenance expenses........... 225,692 | 197,457 570,703 | 517,899 Provision for depreciation and amortization............ 22,022 | 21,554 52,360 | 60,783 General taxes.......................................... 19,237 | 12,713 50,964 | 33,946 Income taxes........................................... 988 | 16,548 22,886 | 30,122 -------- | -------- -------- | -------- Total operating expenses and taxes................. 267,939 | 248,272 696,913 | 642,750 -------- | -------- -------- | -------- | | OPERATING INCOME.......................................... 13,601 | 35,247 70,420 | 84,325 | | OTHER INCOME.............................................. 5,884 | 2,618 16,471 | 12,620 -------- | -------- -------- | -------- | | INCOME BEFORE NET INTEREST CHARGES........................ 19,485 | 37,865 86,891 | 96,945 -------- | -------- -------- | -------- | | NET INTEREST CHARGES: | | Interest on long-term debt............................. 10,054 | 10,558 30,736 | 28,867 Allowance for borrowed funds used during construction.. (234) | (305) (798) | (491) Deferred interest...................................... (167) | (646) (402) | (646) Other interest expense................................. 854 | 1,897 2,025 | 7,270 Subsidiaries' preferred stock dividend requirements.... 1,890 | 1,837 5,669 | 5,512 -------- | -------- -------- | -------- Net interest charges............................... 12,397 | 13,341 37,230 | 40,512 -------- | -------- -------- | -------- | | NET INCOME................................................ $ 7,088 | $ 24,524 $ 49,661 | $ 56,433 ======== | ======== ======== | ======== The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.
81
METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $1,640,974 $1,609,974 Less-Accumulated provision for depreciation............................... 564,051 530,006 ---------- ---------- 1,076,923 1,079,968 Construction work in progress- Electric plant.......................................................... 11,783 14,291 ---------- ---------- 1,088,706 1,094,259 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 154,435 157,699 Long-term notes receivable from associated companies...................... 12,418 12,418 Other..................................................................... 27,147 13,391 ---------- ---------- 194,000 183,508 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 21,327 25,274 Receivables- Customers (less accumulated provisions of $10,981,000 and $12,271,000, respectively, for uncollectible accounts)............................. 121,822 112,257 Associated companies.................................................... 13,474 8,718 Other................................................................... 19,657 16,675 Prepayments and other..................................................... 7,575 12,239 ---------- ---------- 183,855 175,163 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 1,183,325 1,320,412 Goodwill.................................................................. 862,386 784,443 Other..................................................................... 43,649 49,402 ---------- ---------- 2,089,360 2,154,257 ---------- ---------- $3,555,921 $3,607,187 ========== ==========
82
METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- ------------ (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: Common stockholder's equity- Common stock, without par value, authorized 900,000 shares - 859,500 shares outstanding............................................ $1,278,909 $1,274,325 Accumulated other comprehensive income (loss)........................... (37) 11 Retained earnings....................................................... 39,848 14,617 ---------- ---------- Total common stockholder's equity................................... 1,318,720 1,288,953 Company-obligated trust preferred securities.............................. 92,357 92,200 Long-term debt............................................................ 540,002 583,077 ---------- ---------- 1,951,079 1,964,230 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 60,032 30,029 Accounts payable- Associated companies.................................................... 47,197 67,351 Other................................................................... 27,411 36,750 Notes payable to associated companies..................................... 131,780 72,011 Accrued taxes............................................................. 1,953 7,037 Accrued interest.......................................................... 10,841 17,468 Other..................................................................... 10,413 13,652 ---------- ---------- 289,627 244,298 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 271,554 300,438 Accumulated deferred investment tax credits............................... 12,674 13,310 Purchase power contract loss liability.................................... 676,022 730,662 Nuclear fuel disposal costs............................................... 37,395 36,906 Nuclear plant decommissioning costs....................................... 272,680 268,967 Other..................................................................... 44,890 48,376 ---------- ---------- 1,315,215 1,398,659 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $3,555,921 $3,607,187 ========== ========== The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets.
83
METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ----------------------- ---------------------- 2002 2001 2002 2001 -------- --------- -------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 7,088 | $ 24,524 $ 49,661 | $ 56,433 Adjustments to reconcile net income to net | | cash from operating activities- | | Provision for depreciation and amortization........ 22,022 | 21,554 52,360 | 60,783 Other amortization................................. (546) | 249 (1,940) | 1,005 Deferred costs, net................................ 7,678 | (74,600) (1,733) | (98,994) Deferred income taxes, net......................... (1,841) | 34,101 10,349 | 44,978 Investment tax credits, net........................ (212) | (212) (636) | (636) Receivables........................................ (3,494) | 34,773 (17,302) | 20,627 Accounts payable................................... (26,567) | (112,430) (29,492) | (54,684) Accrued taxes...................................... 5 | (12,607) (5,084) | (13,177) Other.............................................. (5,189) | (11,071) (37,056) | (43,904) -------- | --------- -------- | -------- Net cash provided from (used for) operating | | activities ..................................... (1,056) | (95,719) 19,127 | (27,569) -------- | --------- -------- | -------- | | CASH FLOWS FROM FINANCING ACTIVITIES: | | New Financing- | | Long-term debt....................................... -- | 48,100 49,750 | 99,500 Short-term borrowings, net........................... 60,628 | 13,400 59,769 | 13,400 Redemptions and Repayments- | | Long-term debt....................................... 30,000 | -- 60,000 | -- Dividend Payments- | | Common stock......................................... -- | -- 30,000 | 15,000 -------- | --------- -------- | -------- Net cash provided from financing activities...... 30,628 | 61,500 19,519 | 97,900 -------- | --------- -------- | -------- | | CASH FLOWS FROM INVESTING ACTIVITIES: | | Property additions..................................... 11,209 | 12,592 31,996 | 37,614 Decommissioning trust investments...................... 2,371 | 2,371 10,358 | 7,113 Other.................................................. -- | 446 239 | 5,001 -------- | --------- -------- | -------- Net cash used for investing activities........... 13,580 | 15,409 42,593 | 49,728 -------- | --------- -------- | -------- | | Net increase (decrease) in cash and cash equivalents...... 15,992 | (49,628) (3,947) | 20,603 Cash and cash equivalents at beginning of period.......... 5,335 | 73,670 25,274 | 3,439 -------- | --------- -------- | -------- Cash and cash equivalents at end of period................ $ 21,327 | $ 24,042 $ 21,327 | $ 24,042 ======== | ========= ======== | ======== The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.
84 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Metropolitan Edison Company: We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of September 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2002. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2002 85 METROPOLITAN EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in the eastern and south central portions of Pennsylvania, offering regulated electric transmission and distribution services. Met-Ed also provides power to those customers electing to retain them as their power supplier. Met-Ed's regulatory plan itemizes, or unbundles, the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Met-Ed was formerly a wholly owned subsidiary of GPU, Inc., which merged with FirstEnergy on November 7, 2001. In September 2002, Met-Ed established a reserve of $143.2 million for its PLR deferred energy costs (see Pennsylvania Regulatory Matters). The reserve reflects the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. In the interim financial statements in 2002, Met-Ed had previously disclosed, in consultation with its independent accountants, that the finalization of that potential pre-acquisition contingency relating to the FirstEnergy/GPU merger would be reflected as an adjustment to the allocation of the purchase price prior to the end of the third quarter of 2002. In connection with FirstEnergy finalizing the purchase accounting relating to the FirstEnergy/GPU merger, in the third quarter of 2002, Met-Ed after further consultation with its independent accountants, revised the previously disclosed accounting for this potential pre-acquisition contingency. This resulted in the recognition of a reserve related to deferred energy costs of $112.5 million as an increase to goodwill and a $30.7 million pre-tax charge related to deferred energy costs subsequent to the acquisition date in the income statement in the periods in which these costs were incurred. Accordingly, Met-Ed will be amending its interim consolidated financial statements included in its Form 10-Q filings for the quarters ended March 31, 2002 and June 30, 2002 (see Financial Statement Revision). The consolidated financial statements for the three-month and nine-month periods ended September 30, 2002 reflect the effect of the retroactive application. Results of Operations --------------------- Operating revenues decreased by $2.0 million or 0.7% in the third quarter of 2002, and increased $40.3 million or 5.5% in the first nine months of 2002, compared to the same periods in 2001. The sources of the changes in operating revenues, as compared to the same periods in 2001, are summarized in the following table.
Sources of Operating Revenue Changes ------------------------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Change in kilowatt-hour sales due to level of retail customers shopping for generation service........... $(15.2) $ 41.6 Change in other retail kilowatt-hour sales............. 29.8 29.1 Change in wholesale sales.............................. (17.5) (27.2) All other changes...................................... 0.9 (3.2) ------ ------ Net Increase (Decrease) in Operating Revenues.......... $ (2.0) $ 40.3 ====== ======
Electric Sales During the first half of 2002, Met-Ed had experienced a significant reduction in the number of customers who received their power from alternate suppliers, which had a positive effect on operating revenues. However, during the third quarter of 2002, this trend reversed slightly as more industrial and commercial customers shopped for power, which resulted in a decrease in operating revenues during that period. Warmer weather during the third quarter of 2002, compared to third quarter of 2001, contributed to an increase in retail distribution deliveries. Partially offsetting this increase in revenues were lower sales to industrial customers due to a decline in economic conditions, as well as reduced revenues from wholesale customers. Changes in kilowatt-hour deliveries by customer class during the three and nine month periods ended September 30, 2002, as compared to the same periods in 2001, are summarized in the following table: 86 Changes in Distribution Deliveries and Wholesale Generation Sales ------------------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Residential............................. 13.0 % 2.0 % Commercial.............................. 3.6 % 2.0 % Industrial.............................. (0.9)% (4.7)% ----- ----- Total Retail....................... 5.5 % (0.2)% Wholesale............................... (37.9)% (13.4)% ----- ----- Total................................... 0.6 % (1.4)% ===== ===== Operating Expenses and Taxes Total operating expenses and taxes increased $19.7 million in the third quarter of 2002, and $54.2 million in the first nine months of 2002, compared to the same periods in 2001. A majority of the increase in both periods was due to higher purchased power costs, as Met-Ed required additional power to satisfy its provider of last resort (PLR) obligation to customers who returned from alternate suppliers in the first nine months of 2002. In addition, the establishment of a reserve reflecting the potential adverse impact of a pending Pennsylvania Supreme Court decision resulted in a 2002 charge to purchased power costs. (See Pennsylvania Regulatory Matters for further discussion.) Other operating costs decreased $8.8 million and $13.0 million in the quarter and nine months ended September 30, 2002, respectively, compared to the same periods in 2001. The decreases were due primarily to the absence of costs related to early retirement programs offered to certain bargaining unit employees in the first quarter of 2001, the absence of other 2001 employee costs and the absence of costs related to the use of portable generators at certain substations under a pilot program during the third quarter of 2001, partially offset by higher rental and pension costs. General taxes increased $6.5 million and $17.0 million in the quarter and nine months ended September 30, 2002, respectively, compared to the same periods in 2001, due primarily to an increase in Pennsylvania gross receipts taxes. Other Income Other income increased $3.3 million in the third quarter of 2002, and $3.9 million in the first nine months of 2002, compared to the same periods in 2001, primarily due to the absence in 2002 of net losses incurred in 2001 on futures contracts and options, and increased contract work in the third quarter of 2002. Net Interest Charges Net interest charges decreased $0.9 million in the third quarter of 2002, and $3.3 million in the first nine months of 2002, compared to the same periods in 2001, primarily due to reduced short-term borrowing levels and amortization of fair value adjustments recorded in connection with the merger. Interest expense was further reduced by the redemption of $30 million of notes in the first quarter of 2002; however, that reduction was partially offset by the issuance of $100 million of notes in September 2001 and $50 million of notes in May 2002 (used to refinance $30 million of notes in July 2002). Financial Statements Revision During the third quarter of 2002, Met-Ed established a reserve and recorded a non-cash charge of $30.7 million ($17.9 million net of tax) for deferred energy costs incurred subsequent to the merger (see Pennsylvania Regulatory Matters). The reserve reflects the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. In the interim financial statements in 2002, Met-Ed had previously disclosed, in consultation with its independent accountants, that the finalization of that potential pre-acquisition contingency relating to the FirstEnergy/GPU merger would be reflected as an adjustment to the allocation of the purchase price prior to the end of the third quarter of 2002. In connection with FirstEnergy finalizing the purchase accounting relating to the FirstEnergy/GPU merger, in the third quarter of 2002, Met-Ed after further consultation with its independent accountants, revised the previously disclosed accounting for this potential pre-acquisition contingency. This resulted in the recognition of a reserve related to deferred energy costs of $112.5 million as an increase to goodwill and a $30.7 million pre-tax charge related to deferred energy costs subsequent to the acquisition date in the income statement in the periods in which these costs were incurred. Accordingly, Met-Ed will be amending its interim consolidated financial statements included in its Form 10-Q filings to reflect the redistributed earnings impact of the $30.7 million for the quarters ended March 31, 2002 and June 30, 2002. (see Note 4). The reserve for the $112.5 million of deferred energy costs as of the acquisition date increased goodwill by $65.8 million, net of tax. Should the Pennsylvania Supreme Court ultimately uphold FirstEnergy's appeal, the $30.7 million charge would be reversed into earnings. 87 Capital Resources and Liquidity ------------------------------- Met-Ed has continuing cash requirements for planned capital expenditures, which are expected to be about $20.0 million during the remaining three months of 2002. These requirements are expected to be satisfied from internal cash and/or short-term credit arrangements. As of September 30, 2002, Met-Ed had about $21.3 million of cash and temporary investments and $131.8 million of short-term indebtedness. Met-Ed may borrow from its affiliates on a short-term basis. Met-Ed will not issue first mortgage bonds (FMBs) other than as collateral for senior notes, since its senior note indenture prohibits (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of September 30, 2002, Met-Ed had the capability to issue up to $118.3 million of additional FMBs on the basis of property additions and retired bonds. Met-Ed has no restrictions on the issuance of preferred stock. Postretirement Plans FirstEnergy maintains defined benefit pension plans, as well as several other postretirement employee benefit (OPEB) plans such as health care and life insurance. All of Met-Ed's full-time employees are eligible to participate in these plans. In accordance with the provisions of the Employment Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded status of its pension plans annually to determine if additional funding is necessary. FirstEnergy has pre-funded a portion of the future liabilities related to its OPEB plans. Under the terms of its postretirement benefit plans, FirstEnergy reserves the right to change, modify or terminate the plans. Its pension plan funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA - no contributions have been required since 1985. Due to sharp declines in the equity markets in the United States since the second quarter of 2000, the value of assets held in the trusts to satisfy the obligations of pension plans has significantly decreased. As a result, under the minimum funding requirements of ERISA or the Pension Benefit Guaranty Corporation, FirstEnergy may be required to resume contributing to the plan trusts as early as 2004. FirstEnergy believes that it has adequate access to capital resources through cash generated from operations and through existing lines of credit to support necessary funding requirements based on anticipated plan performance. While OPEB plan assets have also been affected by the sharp declines in the equity market, contributions are voluntary and declines have a limited impact on required future funding. If the market value of FirstEnergy's pension plan assets were to remain unchanged from October 31, 2002, through the end of the year, Met-Ed would be required to record an after-tax charge to equity (other comprehensive income) of approximately $23 million in the fourth quarter of 2002 to recognize its additional minimum pension liability of $39 million. The amount recorded will depend upon the financial markets and interest rates in the remainder of 2002. In addition, pension and other postretirement costs could increase by as much as $12 million in 2003 based on the reduction of plan assets through October 31, 2002, due to adverse equity market conditions, lower rate of return assumptions and the amortization of unrecognized losses, as well as higher health care trend rates for OPEB (see Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting). Market Risk Information ----------------------- Met-Ed uses various market sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. Met-Ed's Risk Policy Committee, comprised of FirstEnergy executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk Met-Ed is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, Met-Ed uses a variety of derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. The change in the fair value of commodity derivative contracts related to energy production during the third quarter of 2002 is summarized in the following table: Change in the Fair Value of Commodity Derivative Contracts ---------------------------------------------------------- (In millions) Outstanding net asset as of June 30, 2002........... $11.3 Increase in value of existing contracts............. 2.0 Change in techniques/assumptions.................... -- Settled contracts................................... 0.1 ----- Outstanding net asset as of September 30, 2002...... $13.4 ===== 88 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, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed utilizes these results in developing estimates of fair value for the later years of applicable electricity contracts for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: Source of Information - Fair Value by Contract Year --------------------------------------------------- 2002* 2003 2004 Thereafter Total ----- ---- ---- ---------- ----- (In millions) Prices actively quoted...... $-- $0.1 $-- $ -- $ 0.1 Prices based on models**.... -- -- -- 13.3 13.3 --- ---- --- ----- ----- Total..................... $-- $0.1 $-- $13.3 $13.4 === ==== === ===== ===== * For the last quarter of 2002. ** Relates to an embedded option that is offset by a regulatory liability and does not affect earnings. Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on Met-Ed's consolidated financial position or cash flows as of September 30, 2002. Pennsylvania Regulatory Matters ------------------------------- In June and July 2001, several parties had filed Petitions for Review with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders which approved the FirstEnergy/GPU merger and provided rate relief for Met-Ed. 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 Met-Ed's PLR obligation, and rejected those parts of the settlement that permitted the Company to defer for accounting purposes the difference between its wholesale power costs and the amount collected from retail customers. Met-Ed and 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's decision. Also on March 25, 2002, Citizens Power filed a motion seeking an appeal of the Commonwealth Court's decision to affirm the FirstEnergy/GPU merger with the Supreme Court of Pennsylvania. In September 2002, Met-Ed established a reserve of $143.2 million for its PLR deferred energy costs. The reserve reflects the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. Met-Ed recorded a non-cash charge of $30.7 million ($17.9 million net of tax) for the deferred energy costs incurred subsequent to the merger. The reserve for the remaining $112.5 million of deferred costs increased Met-Ed's goodwill by the net of tax amount of $65.8 million. Significant Accounting Policies ------------------------------- Met-Ed prepares its 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 Met-Ed's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Met-Ed's goodwill will be reviewed for impairment at least annually in accordance with SFAS 142. Met-Ed's annual review was completed in the third quarter of 2002 - the results of that review indicated no impairment of goodwill. Other assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. 89 Purchase Accounting - Acquisition of GPU On November 7, 2001, the merger between FirstEnergy and GPU became effective, and Met-Ed became a wholly owned subsidiary of FirstEnergy. The merger was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities were based primarily on estimates. The adjustments reflected in Met-Ed's records, which are subject to adjustment in 2002 when finalized, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill, which totaled $862.4 million at September 30, 2002. 89 Regulatory Accounting Met-Ed is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Met-Ed is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded - $1.2 billion as of September 30, 2002. Met-Ed regularly reviews 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. In September 2002, Met-Ed established a $143.2 million reserve, reflecting the current estimate of potential adverse impact in a pending Pennsylvania Supreme Court decision. (See Pennsylvania Regulatory Matters for further discussion.) 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. Met-Ed continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Met-Ed enters into commodity contracts, which increase the impact of derivative accounting judgments. Revenue Recognition Met-Ed follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," Met-Ed periodically evaluates its 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 impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, Met-Ed recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and assumptions of future activities. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation. 90 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. In selecting an assumed discount rate, FirstEnergy considers fixed income security yields for AA rated corporate debt. Corporate bond yields, as well as interest rates in general, have declined in the first nine months of 2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If the discount rate is reduced from the current assumed rate, pension and OPEB liabilities and costs would increase in 2003. FirstEnergy's assumed rate of return on its pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2001, 2000 and 1999, return on plan assets has been (5.5%), (0.3%) and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed assuming a 10.25% rate of return on plan assets, consistent with long-term historical returns produced by the plan's investment portfolio. If a lower rate of return were to be assumed in 2003, Met-Ed's reported pension costs would increase. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is moderated due to smaller asset balances. However, medical cost trends have significantly increased which could affect future postretirement benefit costs. As a result of the reduced market value of its pension plan assets (see Postretirement Plans), FirstEnergy could be required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits." The offset to the liability would be recorded as a reduction to common stockholder's equity through an after-tax charge to other comprehensive income (OCI), and would not affect net income for 2002. The charge to OCI would reverse in future periods if the fair value of trust assets exceeds the accumulated benefit obligation. The amount of pension liability to be recorded as of December 31, 2002 will depend upon the assumed discount rate (and any other change in FirstEnergy's assumptions) and actual asset returns experienced in 2002. Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- 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 as of January 1, 2003. SFAS 143 requires the fair value of a liability for an asset retirement obligation to 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, both resulting in a period expense. 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 various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the fourth quarter of 2002. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," 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 will be 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. 91
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) OPERATING REVENUES........................................ $269,359 | $265,603 $749,755 | $740,030 -------- | -------- -------- | -------- | | | | OPERATING EXPENSES AND TAXES: | | Purchased power........................................ 191,756 | 163,968 480,608 | 475,359 Other operating costs.................................. 27,759 | 33,602 99,977 | 114,367 -------- | -------- -------- | -------- Total operation and maintenance expenses........... 219,515 | 197,570 580,585 | 589,726 Provision for depreciation and amortization............ 16,098 | 13,674 45,743 | 43,302 General taxes.......................................... 17,744 | 12,486 47,200 | 36,637 Income taxes........................................... 3,040 | 15,104 18,839 | 16,406 -------- | -------- -------- | -------- Total operating expenses and taxes................. 256,397 | 238,834 692,367 | 686,071 -------- | -------- -------- | -------- | | OPERATING INCOME.......................................... 12,962 | 26,769 57,388 | 53,959 | | OTHER INCOME (EXPENSE).................................... 1,067 | (1,234) 2,154 | 785 -------- | -------- -------- | -------- | | INCOME BEFORE NET INTEREST CHARGES........................ 14,029 | 25,535 59,542 | 54,744 -------- | -------- -------- | -------- | | NET INTEREST CHARGES: | | Interest on long-term debt............................. 7,796 | 8,735 24,124 | 25,154 Allowance for borrowed funds used during construction.. 84 | 224 (199) | (60) Deferred interest...................................... (869) | (592) (2,311) | (592) Other interest expense................................. 684 | 956 2,123 | 5,275 Subsidiaries' preferred stock dividend requirements.... 1,888 | 1,835 5,665 | 5,505 -------- | -------- -------- | -------- Net interest charges............................... 9,583 | 11,158 29,402 | 35,282 -------- | -------- -------- | -------- | | NET INCOME................................................ $ 4,446 | $ 14,377 $ 30,140 | $ 19,462 ======== | ======== ======== | ======== The preceding Notes to Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.
92
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $1,873,598 $1,845,187 Less-Accumulated provision for depreciation............................... 668,941 630,957 ---------- ---------- 1,204,657 1,214,230 Construction work in progress - electric plant ......................................................... 9,872 12,857 ---------- ---------- 1,214,529 1,227,087 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Non-utility generation trusts............................................. 123,658 154,067 Nuclear plant decommissioning trusts...................................... 89,274 96,610 Long-term notes receivable from associated companies...................... 15,515 15,515 Other..................................................................... 7,595 2,265 ---------- ---------- 236,042 268,457 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 32,310 39,033 Receivables- Customers (less accumulated provisions of $11,849,000 and $14,719,000, respectively, for uncollectible accounts)............................. 93,780 107,170 Associated companies.................................................... 52,349 40,203 Other................................................................... 16,551 14,842 Prepayments and other..................................................... 6,509 8,605 ---------- ---------- 201,499 209,853 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 574,290 769,807 Goodwill.................................................................. 873,600 797,362 Accumulated deferred income taxes......................................... 26,764 -- Other..................................................................... 24,057 27,703 ---------- ---------- 1,498,711 1,594,872 ---------- ---------- $3,150,781 $3,300,269 ========== ==========
93
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2002 2001 ------------- ------------ (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: Common stockholder's equity- Common stock, par value $20 per share, authorized 5,400,000 shares, 5,290,596 shares outstanding.................................. $ 105,812 $ 105,812 Other paid-in capital................................................... 1,192,849 1,188,190 Accumulated other comprehensive income.................................. 428 1,779 Retained earnings....................................................... 31,437 10,795 ---------- ---------- Total common stockholder's equity................................... 1,330,526 1,306,576 Company-obligated trust preferred securities ............................. 92,160 92,000 Long-term debt............................................................ 470,950 472,400 ---------- ---------- 1,893,636 1,870,976 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 25,798 50,756 Accounts payable- Associated companies.................................................... 121,360 126,390 Other................................................................... 28,179 38,720 Notes payable to associated companies..................................... 103,932 77,623 Accrued taxes............................................................. 6,286 29,255 Accrued interest.......................................................... 18,662 12,284 Other..................................................................... 7,885 10,993 ---------- ---------- 312,102 346,021 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... -- 21,682 Accumulated deferred investment tax credits............................... 11,100 11,956 Nuclear plant decommissioning costs....................................... 137,364 135,483 Nuclear fuel disposal costs............................................... 18,697 18,453 Power purchase contract loss liability.................................... 750,941 867,046 Other..................................................................... 26,941 28,652 ---------- ---------- 945,043 1,083,272 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $3,150,781 $3,300,269 ========== ========== The preceding Notes to Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these balance sheets.
94
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2002 2001 2002 2001 -------- --------- -------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: | Net income................................................ $ 4,446 | $ 14,377 $ 30,140 | $ 19,462 Adjustments to reconcile net income to net | | cash from operating activities- | | Provision for depreciation and amortization........ 16,098 | 13,674 45,743 | 43,302 Other amortization................................. (70) | 449 117 | 1,493 Deferred costs, net................................ (13,468) | (91,802) (41,168) | (126,557) Deferred income taxes, net......................... 4,525 | 34,330 3,087 | 43,212 Investment tax credits, net........................ (285) | (285) (856) | (856) Receivables........................................ 9,186 | (42,777) (466) | (33,276) Accounts payable................................... (16,663) | 21,448 (15,570) | 64,528 Accrued taxes...................................... (3,144) | 882 (22,969) | (4,762) Other.............................................. 21,888 | (11,629) 7,689 | (22,600) -------- | --------- -------- | --------- Net cash provided from (used for) operating | | activities ..................................... 22,513 | (61,333) 5,747 | (16,054) -------- | --------- -------- | --------- | | CASH FLOWS FROM FINANCING ACTIVITIES: | | New Financing- | | Short-term borrowings, net........................... 444 | -- 26,309 | 9,200 Contributions from parent............................ -- | -- -- | 50,000 Redemptions and Repayments- | | Long-term debt....................................... -- | -- 24,973 | -- Short-term borrowings, net........................... -- | 44,000 -- | -- Dividend Payments- | | Common stock......................................... -- | -- 14,000 | -- -------- | --------- -------- | --------- Net cash used for (provided from) financing | | activities ..................................... (444) | 44,000 12,664 | (59,200) -------- | --------- -------- | --------- | | CASH FLOWS FROM INVESTING ACTIVITIES: | | Property additions..................................... 10,958 | 8,157 33,775 | 37,529 Proceeds from non-utility generation trusts............ -- | (2,154) (34,208) | (18,339) Decommissioning trust investments...................... -- | -- -- | 15 Other.................................................. -- | 801 239 | 4,972 -------- | --------- -------- | --------- Net cash used for (provided from) investing | | activities ..................................... 10,958 | 6,804 (194) | 24,177 -------- | --------- -------- | --------- | | Net increase (decrease) in cash and cash equivalents...... 11,999 | (112,137) (6,723) | 18,969 Cash and cash equivalents at beginning of period.......... 20,311 | 131,686 39,033 | 580 -------- | --------- -------- | --------- Cash and cash equivalents at end of period................ $ 32,310 | $ 19,549 $ 32,310 | $ 19,549 ======== | ========= ======== | ========= The preceding Notes to Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.
95 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Pennsylvania Electric Company: We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of September 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2002. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2002 96 PENNSYLVANIA ELECTRIC COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern, western, and south central portions of Pennsylvania, offering regulated electric transmission and distribution services. Penelec also provides power to those customers electing to retain them as their power supplier. Penelec's regulatory plan itemizes, or unbundles, the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Penelec was formerly a wholly owned subsidiary of GPU, Inc., which merged with FirstEnergy on November 7, 2001. In September 2002, Penelec established a reserve of $143.9 million for its PLR deferred energy costs (see Pennsylvania Regulatory Matters). The reserve reflects the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. In the interim financial statements in 2002, Penelec had previously disclosed, in consultation with its independent accountants, that the finalization of that potential pre-acquisition contingency relating to the FirstEnergy/GPU merger would be reflected as an adjustment to the allocation of the purchase price prior to the end of the third quarter of 2002. In connection with FirstEnergy finalizing the purchase accounting relating to the FirstEnergy/GPU merger, in the third quarter of 2002, Penelec after further consultation with its independent accountants, revised the previously disclosed accounting for this potential pre-acquisition contingency. This resulted in the recognition of a reserve related to deferred energy costs of $118.8 million as an increase to goodwill and a $25.1 million pre-tax charge related to deferred energy costs subsequent to the acquisition date in the income statement in the periods in which these costs were incurred. Accordingly, Penelec will be amending its interim consolidated financial statements included in its Form 10-Q filings for the quarters ended March 31, 2002 and June 30, 2002 (see Financial Statement Revision). The consolidated financial statements for the three-month and nine-month periods ended September 30, 2002 reflect the effect of the retroactive application. Results of Operations --------------------- Operating revenues increased by $3.7 million or 1.4% in the third quarter of 2002, and $9.7 million or 1.3% in the first nine months of 2002, compared to the same periods in 2001. The sources of the changes in operating revenues, as compared to the same periods in 2001, are summarized in the following table.
Sources of Operating Revenue Changes ------------------------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Change in kilowatt-hour sales due to level of retail customers shopping for generation service........... $ (1.9) $ 58.5 Change in other retail kilowatt-hour sales............. 19.3 10.5 Change in wholesale sales.............................. (12.3) (52.9) All other changes...................................... (1.4) (6.4) ------- ------ Net Increase in Operating Revenues..................... $ 3.7 $ 9.7 ====== ======
Electric Sales In the first nine months of 2002, a reduction in the number of customers who received their power from alternate suppliers continued to have a positive effect on operating revenues. During the first nine months of 2001, 16.3% of kilowatt-hours delivered were to shopping customers, whereas only 5.4% of kilowatt-hours delivered during the same period in 2002 were to shopping customers. In addition, warmer weather in the third quarter of 2002 contributed to an increase in retail distribution deliveries. Partially offsetting these increases were lower sales to wholesale customers during the first nine months of 2002. A decline in economic conditions resulted in a decrease in sales to industrial customers for the nine months ended September 30, 2002; however, economic conditions continued to improve during the third quarter of 2002, resulting in a slight increase in industrial sales during that period. Changes in kilowatt-hour deliveries by customer class during the three and nine month periods ended September 30, 2002, as compared to the same periods in 2001, are summarized in the following table: 97 Changes in Distribution Deliveries and Wholesale Generation Sales ------------------------------ Increase (Decrease) Periods Ending September 30, 2002 --------------------------------- 3 Months 9 Months -------- -------- (In millions) Residential............................ 10.7% 2.4% Commercial............................. 5.5% 2.5% Industrial............................. 1.1% (2.9)% ----- ----- Total Retail...................... 5.5% 0.7% Wholesale.............................. (45.8)% (65.5)% ----- ----- Total.................................. 0.3% (7.1)% ===== ===== Operating Expenses and Taxes Total operating expenses and taxes increased $17.6 million and $6.3 million in the three and nine month periods ended September 30, 2002, respectively, compared to the same periods in 2001. Purchased power costs increased $27.8 million and $5.2 million in the third quarter of 2002 and the nine months ended September 30, 2002, compared to the same periods in 2001. Increases in purchased power costs were due primarily to the establishment of a reserve reflecting the potential adverse impact of a pending Pennsylvania Supreme Court decision, which resulted in a 2002 charge to purchased power costs. (See Pennsylvania Regulatory Matters for further discussion.) These increases were partially offset by a reduction in power purchased during the third quarter of 2002, as well as by the absence in 2002 of a $16.0 million charge related to the termination of a wholesale energy contract in 2001. Other operating costs decreased $5.8 million and $14.4 million in the quarter and nine months ended September 30, 2002, respectively, compared to the same periods in 2001. These decreases were due primarily to the absence of costs related to early retirement programs offered to certain bargaining unit employees in the first quarter of 2001, reduced other employee costs, and lower uncollectible expenses in 2002. These decreases were offset by higher pension costs. General taxes increased $5.3 million and $10.6 million in the quarter and nine months ended September 30, 2002, respectively, compared to the same periods in 2001, due primarily to an increase in Pennsylvania gross receipts taxes. Net Interest Charges Net interest charges decreased $1.6 million in the third quarter of 2002, and $5.9 million in the first nine months of 2002, compared to the same periods in 2001, primarily due to higher interest deferrals related to Penelec's deferred provider of last resort costs, as well as reduced short-term borrowing levels and amortization of fair market value adjustments recorded in connection with the merger. Financial Statements Revision During the third quarter of 2002, Penelec established a reserve and recorded a non-cash charge of $25.1 million ($14.7 million net of tax) for deferred energy costs incurred subsequent to the merger (see Pennsylvania Regulatory Matters). The reserve reflects the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. In the interim financial statements in 2002, Penelec had previously disclosed, in consultation with its independent accountants, that the finalization of that potential pre-acquisition contingency relating to the FirstEnergy/GPU merger would be reflected as an adjustment to the allocation of the purchase price prior to the end of the third quarter of 2002. In connection with FirstEnergy finalizing the purchase accounting relating to the FirstEnergy/GPU merger, in the third quarter of 2002, Penelec after further consultation with its independent accountants, revised the previously disclosed accounting for this potential pre-acquisition contingency. This resulted in the recognition of a reserve related to deferred energy costs of $118.8 million as an increase to goodwill and a $25.1 million pre-tax charge related to deferred energy costs subsequent to the acquisition date in the income statement in the periods in which these costs were incurred. Accordingly, Penelec will be amending its interim consolidated financial statements included in its Form 10-Q filings to reflect the redistributed earnings impact of the $25.1 million for the quarters ended March 31, 2002 and June 30, 2002 (see Note 4). The reserve for the $118.8 million of deferred energy costs as of the acquisition date increased goodwill by $69.5 million, net of tax. Should the Pennsylvania Supreme Court ultimately uphold FirstEnergy's appeal, the $25.1 million charge would be reversed into earnings. Capital Resources and Liquidity ------------------------------- Penelec has continuing cash requirements for planned capital expenditures and maturing debt. During the remaining three months of 2002, capital requirements for property additions are expected to be about $20.0 million. Penelec also has requirements for maturing long-term debt of $25.2 million during the remainder of 2002. These requirements are expected to be satisfied from internal cash and/or short-term credit arrangements. 98 As of September 30, 2002, Penelec had about $32.3 million of cash and temporary investments and $103.9 million of short-term indebtedness. Penelec may borrow from its affiliates on a short-term basis. Penelec will not issue first mortgage bonds (FMBs) other than as collateral for senior notes, since its senior note indenture prohibits (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of September 30, 2002, Penelec had the capability to issue up to $462.9 million of additional FMBs on the basis of property additions and retired bonds. Penelec has no restrictions on the issuance of preferred stock. Postretirement Plans FirstEnergy maintains defined benefit pension plans, as well as several other postretirement employee benefit (OPEB) plans such as health care and life insurance. All of Penelec's full-time employees are eligible to participate in these plans. In accordance with the provisions of the Employment Retirement Income Security act of 1974 (ERISA), FirstEnergy reviews the funded status of its pension plans annually to determine if additional funding is necessary. FirstEnergy has pre-funded a portion of the future liabilities related to its OPEB plans. Under the terms of its postretirement benefit plans, FirstEnergy reserves the right to change, modify or terminate the plans. Its pension plan funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA - no contributions have been required since 1985. Due to sharp declines in the equity markets in the United States since the second quarter of 2000, the value of assets held in the trusts to satisfy the obligations of pension plans has significantly decreased. As a result, under the minimum funding requirements of ERISA or the Pension Benefit Guaranty Corporation, FirstEnergy may be required to resume contributing to the plan trusts as early as 2004. FirstEnergy believes that it has adequate access to capital resources through cash generated from operations and through existing lines of credit to support necessary funding requirements based on anticipated plan performance. While OPEB plan assets have also been affected by the sharp declines in the equity market, contributions are voluntary and declines have a limited impact on required future funding. If the market value of FirstEnergy's pension plan assets were to remain unchanged from October 31, 2002, through the end of the year, Penelec would be required to record an after-tax charge to equity (other comprehensive income) of approximately $13 million in the fourth quarter of 2002 to recognize its additional minimum pension liability of $21 million. The amount recorded will depend upon the financial markets and interest rates in the remainder of 2002. In addition, pension and other postretirement costs could increase by as much as $14 million in 2003 based on the reduction of plan assets through October 31, 2002, due to adverse equity market conditions, lower rate of return assumptions and the amortization of unrecognized losses, as well as higher health care trend rates for OPEB (see Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting). Market Risk Information ----------------------- Penelec uses various market sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. Penelec's Risk Policy Committee, comprised of FirstEnergy executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk Penelec is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, Penelec uses a variety of derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. The change in the fair value of commodity derivative contracts related to energy production during the third quarter of 2002 is summarized in the following table: Change in the Fair Value of Commodity Derivative Contracts ---------------------------------------------------------- (In millions) Outstanding net asset as of June 30, 2002.............. $5.7 Increase in value of existing contracts................ 1.0 Change in techniques/assumptions....................... ---- Settled contracts...................................... 0.1 ---- Outstanding net asset as of September 30, 2002......... $6.8 ==== 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, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec utilizes these results in developing estimates of fair value for the later years of applicable electricity contracts for both financial 99 reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: Source of Information - Fair Value by Contract Year --------------------------------------------------- 2002* 2003 2004 Thereafter Total ----- ---- ---- ---------- ----- (In millions) Prices actively quoted... $-- $0.1 $-- $ -- $0.1 Prices based on models**. -- -- -- 6.7 6.7 --- ---- --- ---- ---- Total.................. $-- $0.1 $-- $6.7 $6.8 === ==== === ==== ==== * For the last quarter of 2002. ** Relates to an embedded option that is offset by a regulatory liability and does not affect earnings. Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on Penelec's consolidated financial position or cash flows as of September 30, 2002. Pennsylvania Regulatory Matters ------------------------------- In June and July 2001, several parties had filed Petitions for Review with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders which approved the FirstEnergy/GPU merger and provided rate relief for Penelec. 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 Penelec's PLR obligation, and rejected those parts of the settlement that permitted the Company to defer for accounting purposes the difference between its wholesale power costs and the amount collected from retail customers. Penelec and 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's decision. Also on March 25, 2002, Citizens Power filed a motion seeking an appeal of the Commonwealth Court's decision to affirm the FirstEnergy/GPU merger with the Supreme Court of Pennsylvania. In September 2002, Penelec established a reserve of $143.9 million for its PLR deferred energy costs. The reserve reflects the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. Penelec recorded a non-cash charge of $25.1 million ($14.7 million net of tax) for the deferred energy costs incurred subsequent to the merger. The reserve for the remaining $118.8 million of deferred costs increased Penelec's goodwill by the net of tax amount of $69.5 million. Significant Accounting Policies ------------------------------- Penelec prepares its 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 Penelec's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Penelec's goodwill will be reviewed for impairment at least annually in accordance with SFAS 142. Penelec's annual review was completed in the third quarter of 2002 - the results of that review indicated no impairment of goodwill. Other assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Purchase Accounting - Acquisition of GPU On November 7, 2001, the merger between FirstEnergy and GPU became effective, and Penelec became a wholly owned subsidiary of FirstEnergy. The merger was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities were based primarily on estimates. The adjustments reflected in Penelec's records, which are subject to adjustment in 2002 when finalized, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill, which totaled $873.6 million at September 30, 2002. Regulatory Accounting Penelec is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Penelec is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded - $574.3 million as of September 30, 2002. Penelec regularly reviews these assets to assess their ultimate recoverability within the approved 100 regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. In September 2002, Penelec established a $143.9 million reserve, reflecting the current estimate of the potential adverse impact in a pending Pennsylvania Supreme Court decision. (See Pennsylvania Regulatory Matters for further discussion.) 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. Penelec continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Penelec enters into commodity contracts, which increase the impact of derivative accounting judgments. Revenue Recognition Penelec follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," Penelec periodically evaluates its 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 impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, Penelec recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and assumptions of future activities. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation. 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. 101 In selecting an assumed discount rate, FirstEnergy considers fixed income security yields for AA rated corporate debt. Corporate bond yields, as well as interest rates in general, have declined in the first nine months of 2002, which could affect FirstEnergy's discount rate as of December 31, 2002. If the discount rate is reduced from the current assumed rate, pension and OPEB liabilities and costs would increase in 2003. FirstEnergy's assumed rate of return on its pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2001, 2000 and 1999, return on plan assets has been (5.5%), (0.3%) and 13.4%, respectively. FirstEnergy's pension costs in 2002 are being computed assuming a 10.25% rate of return on plan assets, consistent with long-term historical returns produced by the plan's investment portfolio. If a lower rate of return were to be assumed in 2003, Penelec's reported pension costs would increase. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is moderated due to smaller asset balances. However, medical cost trends have significantly increased which could affect future postretirement benefit costs. As a result of the reduced market value of its pension plan assets (see Postretirement Plans), FirstEnergy could be required to recognize an additional minimum liability as prescribed by SFAS 87 and SFAS 132, "Employers' Disclosures about Pension and Postretirement Benefits." The offset to the liability would be recorded as a reduction to common stockholder's equity through an after-tax charge to other comprehensive income (OCI), and would not affect net income for 2002. The charge to OCI would reverse in future periods if the fair value of trust assets exceeds the accumulated benefit obligation. The amount of pension liability to be recorded as of December 31, 2002, will depend upon the assumed discount rate (and any other change in FirstEnergy's assumptions) and actual asset returns experienced in 2002. Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- 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 as of January 1, 2003. SFAS 143 requires the fair value of a liability for an asset retirement obligation to 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, both resulting in a period expense. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," 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 will be 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. 102 Controls and Procedures ----------------------- (a) Evaluation of Disclosure Controls and Procedures The respective registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and 15d-14(c), as of a date within 90 days prior to the filing date of this report (Evaluation Date). Based on that evaluation those officers have concluded that the registrant's disclosure controls and procedures are effective and were designed to bring to their attention, during the period in which this quarterly report was being prepared, material information relating to the registrant and its consolidated subsidiaries by others within those entities. (b) Changes in Internal Controls There have been no significant changes in internal controls or in other factors that could significantly affect those controls subsequent to the Evaluation Date. 103 PART II. OTHER INFORMATION --------------------------- Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits Exhibit Number ------ Met-Ed ------ 12 Fixed charge ratios 99.1 Certification letter from chief executive officer 99.2 Certification letter from chief financial officer Penelec ------- 12 Fixed charge ratios 15 Letter from independent public accountants 99.1 Certification letter from chief executive officer 99.2 Certification letter from chief financial officer JCP&L ----- 12 Fixed charge ratios 15 Letter from independent public accountants 99.2 Certification letter from chief financial officer 99.3 Certification letter from chief executive officer FirstEnergy, OE and Penn ------------------------ 15 Letter from independent public accountants 99.1 Certification letter from chief executive officer 99.2 Certification letter from chief financial officer CEI and TE ---------- 99.1 Certification letter from chief executive officer 99.2 Certification letter from chief financial officer Pursuant to reporting requirements of respective financings, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q. FirstEnergy, OE, CEI, TE and Penn do not have similar financing reporting requirements and have not filed their respective fixed charge ratios. Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of their respective total assets of FirstEnergy and its subsidiaries on a consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec but hereby agree to furnish to the Commission on request any such documents. (b) Reports on Form 8-K FirstEnergy ----------- Eight reports on Form 8-K were filed since June 30, 2002. A report dated August 1, 2002 reported two JCP&L rate filings with the New Jersey Board of Public Utilities. A report dated August 9, 2002 included conformed copies of Statements Under Oath from H. Peter Burg, Chief Executive Officer and Richard H. Marsh, Chief Financial Officer, dated August 8, 2002, as Exhibits. A report dated August 12, 2002 reported updated information following FirstEnergy's August 8, 2002 notification to NRG Energy and its NRG Able Acquisition LLC affiliate that November 29, 2001 agreements for the NRG purchase of four power plants from subsidiaries of FirstEnergy had been canceled because of the affiliate's anticipatory breach of the agreements. A report dated August 23, 2002 reported updated information provided to the investment community on activities associated with efforts to return the Davis-Besse Nuclear Power Station to service in a safe and reliable manner and other items. A report dated September 11, 2002 reported that research was being conducted on the original reactor head of Davis-Besse. A report dated September 24, 2002 reported updated information provided to the investment community on activities associated with efforts to return Davis-Besse to service; Met-Ed and Penelec 104 had elected to assign certain provider of last resort responsibilities to an unregulated supply affiliate through a wholesale power transaction; and a cost reduction initiative focused on corporate support services. A report dated October 7, 2002 reported an update of the cost and return to service schedule estimates for Davis-Besse. A report dated October 31, 2002 reported on plans for instrumentation tubes inspections on the bottom of the Davis-Besse reactor vessel. OE and Penn ----------- OE and Penn each filed one report on Form 8-K since June 30, 2002. A report dated September 24, 2002 reported a cost reduction initiative focused on corporate support services. CEI and TE ---------- CEI and TE each filed six reports on Form 8-K since June 30, 2002. A report dated August 12, 2002 reported updated information following FirstEnergy's August 8, 2002 notification to NRG Energy and its NRG Able Acquisition LLC affiliate that November 29, 2001 agreements for the NRG purchase of four power plants from subsidiaries of FirstEnergy had been canceled because of the affiliate's anticipatory breach of the agreements. A report dated August 23, 2002 reported updated information provided to the investment community on activities associated with efforts to return the Davis-Besse Nuclear Power Station to service in a safe and reliable manner and other items. A report dated September 11, 2002 reported that research was being conducted on the original reactor head of Davis-Besse. A report dated September 24, 2002 reported updated information provided to the investment community on activities associated with efforts to return Davis-Besse to service and a cost reduction initiative focused on corporate support services. A report dated October 7, 2002 reported an update of the cost and return to service schedule estimates for Davis-Besse. A report dated October 31, 2002 reported on plans for instrumentation tubes inspections on the bottom of the Davis-Besse reactor vessel. JCP&L ----- JCP&L filed two reports on Form 8-K since June 30, 2002. A report dated August 1, 2002 reported two JCP&L rate filings with the New Jersey Board of Public Utilities. A report dated September 24, 2002 reported a cost reduction initiative focused on corporate support services. Met-Ed and Penelec ------------------ Met-Ed and Penelec each filed one report on Form 8-K since June 30, 2002. A report dated September 24, 2002 reported Met-Ed and Penelec had elected to assign certain provider of last resort responsibilities to an unregulated supply affiliate through a wholesale power transaction and a cost reduction initiative focused on corporate support services. 105 SIGNATURE Pursuant to the requirements 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. November 13, 2002 FIRSTENERGY CORP. ----------------- Registrant OHIO EDISON COMPANY ------------------- Registrant THE CLEVELAND ELECTRIC ---------------------- ILLUMINATING COMPANY -------------------- Registrant THE TOLEDO EDISON COMPANY ------------------------- Registrant PENNSYLVANIA POWER COMPANY -------------------------- Registrant JERSEY CENTRAL POWER & LIGHT COMPANY ------------------------------------ Registrant METROPOLITAN EDISON COMPANY --------------------------- Registrant PENNSYLVANIA ELECTRIC COMPANY ----------------------------- Registrant /s/ Harvey L. Wagner --------------------------------- Harvey L. Wagner Vice President, Controller and Chief Accounting Officer 106 Certification I, H. Peter Burg, certify that: 1. I have reviewed this quarterly report on Form 10-Q of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Metropolitan Edison Company and Pennsylvania Electric Company; 2. Based on my knowledge, this quarterly 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 quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly 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: November 13, 2002 ---------------------------- Chief Executive Officer 107 Certification I, Earl T. Carey, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Jersey Central Power & Light Company; 2. Based on my knowledge, this quarterly 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 quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly 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: November 13, 2002 ---------------------------- Chief Executive Officer 108 Certification I, Richard H. Marsh, certify that: 1. I have reviewed this quarterly report on Form 10-Q of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company; 2. Based on my knowledge, this quarterly 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 quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly 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: November 13, 2002 ---------------------------- Chief Financial Officer 109