10-Q 1 jun02.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 June 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 AUGUST 8, 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............................... 1-9 FirstEnergy Corp. Consolidated Statements of Income........................... 10 Consolidated Balance Sheets................................. 11-12 Consolidated Statements of Cash Flows....................... 13 Report of Independent Accountants........................... 14 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 15-26 Ohio Edison Company Consolidated Statements of Income........................... 27 Consolidated Balance Sheets................................. 28-29 Consolidated Statements of Cash Flows....................... 30 Report of Independent Accountants........................... 31 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 32-34 The Cleveland Electric Illuminating Company Consolidated Statements of Income........................... 35 Consolidated Balance Sheets................................. 36-37 Consolidated Statements of Cash Flows....................... 38 Report of Independent Accountants........................... 39 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 40-43 The Toledo Edison Company Consolidated Statements of Income........................... 44 Consolidated Balance Sheets................................. 45-46 Consolidated Statements of Cash Flows....................... 47 Report of Independent Accountants........................... 48 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 49-52 Pennsylvania Power Company Statements of Income........................................ 53 Balance Sheets.............................................. 54-55 Statements of Cash Flows.................................... 56 Report of Independent Accountants........................... 57 Management's Discussion and Analysis of Results of Operations and Financial Condition....................... 58-59 Jersey Central Power & Light Company Consolidated Statements of Income........................... 60 Consolidated Balance Sheets................................. 61-62 Consolidated Statements of Cash Flows....................... 63 Report of Independent Accountants........................... 64 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 65-69 TABLE OF CONTENTS (Cont'd) Pages Metropolitan Edison 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........................ 75-78 Pennsylvania Electric Company Consolidated Statements of Income........................... 79 Consolidated Balance Sheets................................. 80-81 Consolidated Statements of Cash Flows....................... 82 Report of Independent Accountants........................... 83 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 84-87 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 OE and the CEI subsidiary trusts that is the obligor on their respective preferred securities included in FirstEnergy's, OE's and CEI's capitalization are $123,711,350 and $103,093,000 principal amount of 9% Junior Subordinated Debentures of OE due December 31, 2025 and of CEI due December 31, 2006, respectively. OE's preferred securities and the related Junior Subordinated Debentures will be optionally redeemed August 15, 2002. Met-Ed and Penelec have each formed statutory business trusts for substantially similar transactions as OE and CEI 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 1 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. 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, interest rate and foreign currency 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 $133.0 million included in Accumulated Other Comprehensive Loss (AOCL) as of June 30, 2002, for derivative hedging activity as compared to the March 31, 2002 balance of $133.6 million in AOCL, resulted from the sale of $6.0 million of derivative losses with Avon, a $3.8 million loss related to current hedging activity and $1.6 million of net hedge gains included in earnings during the quarter. Approximately $15.7 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. 2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES: Capital Expenditures- FirstEnergy's current forecast reflects expenditures of approximately $3.2 billion (OE-$195 million, CEI-$256 million, TE-$129 million, Penn-$45 million, JCP&L-$572 million, Met-Ed-$336 million, Penelec-$387 million, ATSI-$118 million, FES-$814 million and other subsidiaries-$309 million) for property additions and improvements from 2002-2006, of which approximately $911 million (OE-$92 million, CEI-$152 million, TE-$101 million, Penn-$36 million, JCP&L-$115 million, Met-Ed-$56 million, Penelec-$51 million, ATSI-$28 million, FES-$184 million and other subsidiaries -$96 million) is applicable to 2002. Investments for additional nuclear fuel during the 2002-2006 period are estimated to be 2 approximately $515 million (OE-$141 million, CEI-$169 million, TE-$114 million and Penn-$91 million), of which approximately $54 million (OE-$16 million, CEI-$17 million, TE-$11 million and Penn-$10 million) applies to 2002. 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 Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a "draft" 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. 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. Various environmental liabilities have been recognized on the Consolidated Balance Sheet as of June 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. The Companies have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, 3 Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. 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 $57.3 million (JCP&L-$50.0 million, CEI-$2.8 million, TE-$0.2 million, Met-Ed-$0.2 million, Penelec-$0.4 million and other-$3.7 million) as of June 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, Guarantees 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. El 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 $286 million as of June 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. In June 2002, the private TEBSA equity investors, including El Barranquilla, entered into global settlement agreements with the TEBSA Project lenders, and CORELCA (the government-owned Colombian electric utility with an ownership interest in the Project) resolving all outstanding events of default and other disclosure related issues which had been raised regarding the Project. Also in June 2002, the DIAN (the Colombian national tax authority) notified TEBSA that it had determined that TEBSA did not violate certain foreign exchange regulations regarding the Project lease finance arrangements (for which the DIAN had initially sought to assess statutory penalties of approximately $200 million) and that the DIAN had closed the matter. 3 - PENDING DIVESTITURES: FirstEnergy identified certain former GPU international operations for divestiture within twelve months of the merger date. 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. 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. 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 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 anticipated cash flows 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. 4 GPU's former Argentina operations were also identified by FirstEnergy for divestiture within twelve months of the merger date. 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 June 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 expects that preliminary negotiations with those investors may be completed in the third quarter of 2002. If FirstEnergy has not completed the sale of all of its interest in Emdersa or has not reached a definitive agreement to sell such interest by November 6, 2002, 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 by November 6, 2002) would be reflected on FirstEnergy's Consolidated Statement of Income as a "Cumulative Effect of a Change in Accounting". As of June 30, 2002, that adjustment would have reduced FirstEnergy's net income by approximately $95 million ($0.33 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 within twelve months. Sale of Generating Assets- On November 29, 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 MW to NRG Energy Inc. for $1.5 billion ($1.355 billion in cash and $145 million in debt assumption). 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. As a result, FirstEnergy will pursue opportunities with other parties who have expressed interest in purchasing the plants. FirstEnergy believes that an agreement can be reached with another buyer on a timely basis and that no impairment of these assets is appropriate. The 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. 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 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. 5 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 are not achieved by the end of 2005, the transition cost recovery periods could be 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), but any such adjustment would be computed on a class-by-class and pro-rata basis. Based on annualized shopping levels as of June 30, 2002, FirstEnergy believes the remaining maximum potential recovery reductions are OE's of approximately $31 million. 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, with the level of unbundled rate components after July 31, 2003 to be determined in a rate case, which JCP&L filed on August 1, 2002. All parties will have an opportunity to participate in the process and to examine JCP&L's proposed unbundled rates, including distribution and market transition charge rates. The New Jersey Board of Public Utilities (NJBPU) will review the unbundled rate components to establish the appropriate level of rates after July 31, 2003. In addition to basic electric industry deregulation provisions discussed above, the Final Order also confirms 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. JCP&L submitted two rate filings with NJBPU on August 1, 2002. The first filing related to the level of unbundled rate components after July 31, 2003. 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 securitization of the deferred balance. The deferred costs and JCP&L's current Oyster Creek securitization methodology which is similar to the rate filing proposal is discussed in the following paragraph. However, the NJBPU 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. 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 June 30, 2002, the accumulated deferred cost balance totaled approximately $365 million. The Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generation 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. The Final Order also allows for additional 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. 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. 6 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. 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 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. If the February 21, 2002 Order is not overturned by the Pennsylvania Supreme Court, there would be no adverse effect to FirstEnergy's, Met-Ed's or Penelec's net income since the contingency existed prior to the merger. 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. FirstEnergy's net income in the second quarter of 2001 and the first half of 2001 of $146 million and $244 million, respectively, would have been $160 million and $271 million, respectively, excluding goodwill amortization. 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 will 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 second half 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, will result in its accounting for any future impairments or disposals of long-lived assets under the provisions of SFAS 144, but will not change the accounting principles used in previous asset impairments or disposals. Application of SFAS 144 is not anticipated to have a major impact on accounting for impairments or disposal transactions compared to the prior application of SFAS 121 or APB 30. 7 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 electric utility operating companies in Ohio, Pennsylvania and New Jersey that provide electric transmission and distribution services. Its other material business segment consists of the subsidiaries that operate unregulated energy and energy-related businesses. 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. 8
Segment Financial Information ----------------------------- Regulated Competitive Reconciling Services Services Other Adjustments Consolidated --------- ----------- ----- ----------- ------------ (In millions) Three Months Ended: ------------------- June 30, 2002 ------------- External revenues..................... $ 2,161 $ 696 $ 86 $ 6 (a) $ 2,949 Internal revenues..................... 177 417 125 (719) (b) -- Total revenues..................... 2,338 1,113 211 (713) 2,949 Depreciation and amortization......... 233 6 12 -- 251 Net interest charges.................. 156 7 102 (15) (b) 250 Income taxes.......................... 213 5 (33) -- 185 Income before cumulative effect of a change in accounting............... 273 7 (47) -- 233 Net income (loss)..................... 273 7 (47) -- 233 Total assets.......................... 30,261 2,010 2,009 -- 34,280 Property additions.................... 120 72 32 -- 224 June 30, 2001 ------------- External revenues..................... $ 1,260 $ 499 $ 1 $ 44 (a) $ 1,804 Internal revenues..................... 223 448 64 (735) (b) -- Total revenues..................... 1,483 947 65 (691) 1,804 Depreciation and amortization......... 196 4 7 -- 207 Net interest charges.................. 107 13 8 (7) (b) 121 Income taxes.......................... 158 (41) 3 -- 120 Income before cumulative effect of a change in accounting............. 159 (17) 4 -- 146 Net income (loss)..................... 159 (17) 4 -- 146 Total assets.......................... 15,494 2,154 490 -- 18,138 Property additions.................... 36 84 5 -- 125 Six Months Ended: ---------------- June 30, 2002 ------------- External revenues..................... $ 4,156 $1,374 $ 209 $ 12 (a) $ 5,751 Internal revenues..................... 532 827 242 (1,601) (b) -- Total revenues..................... 4,688 2,201 451 (1,589) 5,751 Depreciation and amortization......... 477 13 24 -- 514 Net interest charges.................. 317 17 205 (29) (b) 510 Income taxes.......................... 375 (37) (73) -- 265 Income before cumulative effect of a change in accounting............... 471 (53) (100) -- 318 Net income (loss)..................... 471 (53) (68) -- 350 Total assets.......................... 30,261 2,010 2,009 -- 34,280 Property additions.................... 264 110 46 -- 420 June 30, 2001 ------------- External revenues..................... $ 2,569 $1,132 $ 2 $ 87 (a) $ 3,790 Internal revenues..................... 557 948 129 (1,634) (b) -- Total revenues..................... 3,126 2,080 131 (1,547) 3,790 Depreciation and amortization......... 411 8 15 -- 434 Net interest charges.................. 252 9 16 (30) (b) 247 Income taxes.......................... 225 (28) 7 -- 204 Income before cumulative effect of a change in accounting............. 282 (41) 11 -- 252 Net income (loss)..................... 282 (49) 11 -- 244 Total assets.......................... 15,494 2,154 490 -- 18,138 Property additions.................... 89 178 9 -- 276 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.
9
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ------------------------ ------------------------ 2002 2001 2002 2001 ---------- ---------- ---------- ---------- (In thousands, except per share amounts) REVENUES: Electric utilities..................................... $2,210,316 $1,260,511 $4,264,292 $2,571,800 Unregulated businesses................................. 738,392 543,635 1,486,573 1,218,087 ---------- ---------- ---------- ---------- Total revenues..................................... 2,948,708 1,804,146 5,750,865 3,789,887 ---------- ---------- ---------- ---------- EXPENSES: Fuel and purchased power............................... 802,623 300,528 1,527,642 625,107 Purchased gas.......................................... 145,954 173,557 352,181 526,374 Other operating expenses............................... 936,156 643,846 1,946,807 1,289,249 Provision for depreciation and amortization............ 250,705 206,606 513,533 433,820 General taxes.......................................... 145,106 92,186 317,094 211,608 ---------- ---------- ---------- ---------- Total expenses..................................... 2,280,544 1,416,723 4,657,257 3,086,158 ---------- ---------- ---------- ---------- INCOME BEFORE INTEREST AND INCOME TAXES................... 668,164 387,423 1,093,608 703,729 ---------- ---------- ---------- ---------- NET INTEREST CHARGES: Interest expense....................................... 231,782 116,342 473,347 234,561 Capitalized interest................................... (6,605) (12,296) (12,419) (21,119) Subsidiaries' preferred stock dividends................ 25,105 16,919 49,176 33,853 ---------- ---------- ---------- ---------- Net interest charges............................... 250,282 120,965 510,104 247,295 ---------- ---------- ---------- ---------- INCOME TAXES.............................................. 184,572 120,439 265,401 204,208 ---------- ---------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING.......................................... 233,310 146,019 318,103 252,226 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................................................ $ 233,310 $ 146,019 $ 349,803 $ 243,727 ========== ========== ========== ========== BASIC EARNINGS PER SHARE OF COMMON STOCK: Income before cumulative effect of accounting change... $ .80 $ .67 $1.08 $1.16 Cumulative effect of accounting change (net of income taxes)(Notes 1 and 3)........................... -- -- .11 (.04) ------ ------ ----- ----- Net income............................................ $ .80 $ .67 $1.19 $1.12 ====== ====== ===== ===== WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING............................................ 293,080 218,372 292,935 218,239 ======= ======= ======= ======= DILUTED EARNINGS PER SHARE OF COMMON STOCK: Income before cumulative effect of accounting change... $ .79 $ .67 $1.08 $1.15 Cumulative effect of accounting change (net of income taxes)(Notes 1 and 3).................................. -- -- .11 (.04) ------ ------ ----- ----- Net income............................................ $ .79 $ .67 $1.19 $1.11 ====== ====== ===== ===== WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING............................................ 294,589 219,540 294,472 219,235 ======= ======= ======= ======= DIVIDENDS DECLARED PER SHARE OF COMMON STOCK.............. $.375 $.375 $ .75 $ .75 ===== ===== ====== ====== 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) June 30, December 31, 2002 2001 ----------- ------------ (In thousands) ASSETS ------ CURRENT ASSETS: Cash and cash equivalents................................................. $ 359,050 $ 220,178 Receivables- Customers (less accumulated provisions of $63,387,000 and $65,358,000, respectively, for uncollectible accounts)............................. 1,069,580 1,074,664 Other (less accumulated provisions of $7,490,000 and $7,947,000, respectively, for uncollectible accounts)............................. 562,201 473,550 Materials and supplies, at average cost- Owned................................................................... 243,785 256,516 Under consignment....................................................... 157,312 141,002 Other..................................................................... 355,996 336,610 ----------- ----------- 2,747,924 2,502,520 ----------- ----------- ASSETS PENDING SALE (Note 3)................................................. 299,502 3,418,225 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT: In service................................................................ 20,330,032 19,981,749 Less--Accumulated provision for depreciation.............................. 8,428,662 8,161,022 ----------- ----------- 11,901,370 11,820,727 Construction work in progress............................................. 582,559 607,702 ----------- ----------- 12,483,929 12,428,429 ----------- ----------- INVESTMENTS: Capital trust investments................................................. 1,109,606 1,166,714 Nuclear plant decommissioning trusts...................................... 1,063,306 1,014,234 Letter of credit collateralization........................................ 277,763 277,763 Pension investments....................................................... 288,609 273,542 Other..................................................................... 964,699 898,311 ----------- ----------- 3,703,983 3,630,564 ----------- ----------- DEFERRED CHARGES: Regulatory assets......................................................... 8,593,052 8,912,584 Goodwill.................................................................. 5,604,967 5,600,918 Other..................................................................... 846,231 858,273 ----------- ----------- 15,044,250 15,371,775 ----------- ----------- $34,279,588 $37,351,513 =========== ===========
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FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, 2002 2001 ------------ ------------ (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... $ 2,320,010 $ 1,867,657 Short-term borrowings..................................................... 644,849 614,298 Accounts payable.......................................................... 741,958 704,184 Accrued taxes............................................................. 505,275 418,555 Other..................................................................... 989,722 1,064,763 ----------- ----------- 5,201,814 4,669,457 ----------- ----------- LIABILITIES RELATED TO ASSETS PENDING SALE (Note 3).......................... 135,531 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................................................... 6,106,334 6,113,260 Accumulated other comprehensive loss.................................... (134,035) (169,003) Retained earnings....................................................... 1,652,006 1,521,805 Unallocated employee stock ownership plan common stock - 4,461,795 and 5,117,375 shares, respectively.......................... (88,615) (97,227) ----------- ----------- Total common stockholders' equity................................... 7,565,454 7,398,599 Preferred stock of consolidated subsidiaries- Not subject to mandatory redemption..................................... 335,123 480,194 Subject to mandatory redemption......................................... 20,379 65,406 Subsidiary-obligated mandatorily redeemable preferred securities.......... 409,658 529,450 Long-term debt............................................................ 11,076,972 11,433,313 ----------- ----------- 19,407,586 19,906,962 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 2,757,711 2,684,219 Accumulated deferred investment tax credits............................... 247,990 260,532 Nuclear plant decommissioning costs....................................... 1,252,100 1,201,599 Power purchase contract loss liability.................................... 3,207,954 3,566,531 Other postretirement benefits............................................. 870,703 838,943 Other..................................................................... 1,198,199 1,268,517 ----------- ----------- 9,534,657 9,820,341 ----------- ----------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ----------- ----------- $34,279,588 $37,351,513 =========== =========== The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these balance sheets.
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FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ----------------------- ----------------------- 2002 2001 2002 2001 --------- --------- --------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 233,310 $ 146,019 $ 349,803 $ 243,727 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 250,705 206,606 513,533 433,820 Nuclear fuel and lease amortization................ 19,598 24,226 40,563 48,201 Other amortization, net............................ (4,386) (4,039) (7,923) (7,672) Deferred costs recoverable as regulatory assets.... (68,936) -- (139,070) -- Deferred income taxes, net......................... 50,355 (19,373) 43,421 (35,308) Investment tax credits, net........................ (6,967) (4,988) (13,713) (9,986) Cumulative effect of accounting change............. -- -- (45,300) 14,338 Receivables........................................ (150,157) (5,609) (83,567) 23,585 Materials and supplies............................. (21,742) (37,219) (3,579) (44,262) Accounts payable................................... 47,766 (38,019) 37,774 (107,679) Other.............................................. (87,423) (99,111) 34,265 (168,168) --------- --------- --------- --------- Net cash provided from operating activities...... 262,123 168,493 726,207 390,596 --------- --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... 261,699 254,877 366,730 255,499 Short-term borrowings, net........................... -- 16,367 30,551 58,481 Redemptions and Repayments- Common stock......................................... -- -- -- 15,308 Preferred stock...................................... 5,000 10,716 190,299 10,716 Long-term debt....................................... 194,738 74,345 378,643 95,561 Short-term borrowings, net........................... 85,005 -- -- -- Common stock dividend payments......................... 109,876 81,864 219,602 163,617 --------- --------- --------- --------- Net cash used for (provided from) financing activities ..................................... 132,920 (104,319) 391,263 (28,778) --------- --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... 224,399 125,322 419,691 276,498 Proceeds from sale of Midlands......................... (155,034) -- (155,034) -- Avon cash and cash equivalents(Note 3)................. 380,496 -- (31,326) -- Net assets held for sale............................... (63,624) -- (2,059) -- Cash investments....................................... (68,365) (3,463) (64,022) (32,601) Other.................................................. 99,998 (11,770) 28,822 19,516 --------- --------- --------- --------- Net cash used for investing activities........... 417,870 110,089 196,072 263,413 --------- --------- --------- --------- Net increase (decrease) in cash and cash equivalents...... (288,667) 162,723 138,872 155,961 Cash and cash equivalents at beginning of period*......... 647,717 42,496 220,178 49,258 --------- --------- --------- --------- Cash and cash equivalents at end of period*............... $ 359,050 $ 205,219 $ 359,050 $ 205,219 ========= ========= ========= ========= * 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.
13 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 June 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and six-month periods ended June 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 August 8, 2002 14 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 of 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 distribution 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 second quarter of 2002 was $233.3 million, or basic earnings of $0.80 per share of common stock ($0.79 diluted), compared to $146.0 million, or $0.67 per share of common stock (basic and diluted) in the second quarter of 2001. During the first six months of 2002, net income was $349.8 million, or $1.19 per share of common stock (basic and diluted), compared to net income of $243.7 million, or basic earnings of $1.12 per share of common stock ($1.11 diluted) in the first six months of 2001. Results in the first half of 2002 and 2001 include the cumulative effect of accounting changes (described below). Before the cumulative effect of accounting changes, net income was $318.1 million in the first six months of 2002, compared to $252.2 million for the same period of 2001. Basic and diluted earnings per share of common stock before the cumulative effect of accounting changes were $1.08 in the first half of 2002, compared to $1.16 ($1.15 diluted) in the first six months of 2001. Results for the second quarter and first half 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 second quarter and year-to-date periods of 2002. Costs related to the extended outage at the Davis-Besse nuclear plant (see Supply Plan) reduced earnings by $0.09 per share in the second quarter and year-to-date periods of 2002. Several one-time charges resulted in a comparative net reduction to earnings of $0.14 per share of common stock. The cessation of goodwill amortization beginning January 1, 2002, upon implementation of Statement of Financial Accounting Standard No. (SFAS) 142, "Goodwill and Other Intangible Assets," added $0.05 per share of common stock (basic and diluted), in the second quarter of 2002, compared to the same period last year and $0.09 per share of common stock (basic and diluted) in the first half of 2002, compared to the corresponding period of 2001. Revenues Total revenues increased $1.1 billion in the second quarter and $2.0 billion in the first six months of 2002, compared to the same periods in 2001. Excluding results of the former GPU companies, total revenues decreased by $12.2 million or 0.7% in the second quarter and $344.6 million or 9.1% in the first half of 2002, compared to the corresponding periods of 2001. Sources of changes in pre-merger and post-merger revenues during the second quarter and first six months of 2002, compared with the corresponding periods of 2001, are summarized in the following table: 15 Sources of Revenue Changes -------------------------- Increase (Decrease) Periods Ending June 30, 2002 ---------------------------- 3 Months 6 Months ----------- ----------- (In millions) Pre-Merger Companies: Electric Utilities (Regulated Services): Retail electric sales........................ $ (16.3) $ (217.5) Other revenues............................... (20.2) (17.7) -------- -------- Total Electric Utilities....................... (36.5) (235.2) -------- -------- Unregulated Businesses (Competitive Services): Retail electric sales........................ 8.2 (0.8) Wholesale electric sales..................... 62.9 124.3 Gas sales.................................... (14.9) (141.6) Other businesses............................. (31.9) (91.3) -------- -------- Total Unregulated Businesses................... 24.3 (109.4) -------- -------- Total Pre-Merger Companies..................... (12.2) (344.6) -------- -------- Former GPU Companies: Electric utilities........................... 986.3 1,927.8 Unregulated businesses....................... 230.8 487.2 -------- -------- Total Former GPU Companies..................... 1,217.1 2,415.0 Intercompany Revenues.......................... (60.3) (109.4) -------- -------- Net Revenue Increase........................... $1,144.6 $1,961.0 ======== ======== Electric Sales Shopping by Ohio customers for alternative energy suppliers combined with a weak but recovering economy reduced retail electric sales revenues for FirstEnergy's pre-merger electric utility operating companies (EUOCs) by $16.3 million in the second quarter and $217.5 million in the first six months of 2002, compared to the same periods of 2001. Kilowatt-hour sales to regulated retail customers decreased 10.1% in the second quarter and 18.4% in the first half of 2002, which reduced retail electric sales revenues by $24.5 million and $127.0 million, respectively. Sales of electric generation by alternative suppliers in the EUOCs' franchise areas increased to 21.1% of total energy delivered in the second quarter of 2002, compared to 11.8% in the same quarter last year. In the first six months of 2002, the EUOCs' share of franchise-area sales declined by 13.4 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 second quarter impact was moderated by a gradual recovery, as well as warmer weather in June, compared to the second quarter of 2001. Revenue from distribution deliveries increased by $28.4 million, more than offsetting the lower generation sales revenues in the second quarter of 2002, compared to the same quarter of 2001, due to an overall 0.6% net increase in kilowatt-hour deliveries to franchise customers. The net increase resulted from additional kilowatt-hour deliveries to residential customers (9.4% higher) that were substantially offset by a 2.4% decrease in deliveries to commercial and industrial customers. Unusually warm weather in June 2002 increased the air-conditioning demand of residential customers, compared to last year. During the first six months of 2002, a 4.6% decline in kilowatt-hour deliveries to franchise customers reduced retail electric sales revenues by $42.1 million, compared to the same period in 2001. The reduced distribution deliveries resulted from a 6.9% reduction in deliveries to the commercial and industrial sectors, which were offset in part by a 1.2% increase in kilowatt-hour deliveries to residential customers. While some evidence of a modest economic recovery began in the first half of 2002, the tentative recovery has not been broad based and reduced sales to the steel sector continue to depress FirstEnergy's industrial sector. 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 - $20.5 million in the second quarter and $48.4 million in the first half 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 $8.2 million in the second quarter resulting from a 14.9% increase in kilowatt-hour sales from the same quarter last year. Despite a 6.7% increase in kilowatt-hour sales in the first six months of 2002, a change in sales mix resulted in revenues that were nearly unchanged, compared to the corresponding period of 2001. The increase in FirstEnergy's competitive kilowatt-hour sales in 2002 16 occurred primarily in Ohio. As of June 30, 2002, approximately one-third of FirstEnergy's Ohio franchise-area customers serviced by alternative suppliers were supplied by FES. Wholesale revenues increased $65.7 million in the second quarter and $140.1 million in the year-to-date period of 2002, compared to the corresponding periods last year. Kilowatt-hour sales to the wholesale markets were correspondingly higher, increasing by 67% in the second quarter and by 83% in the first six months of 2002, compared to the same periods last year. The higher kilowatt-hour sales resulted from the increased availability of power for the wholesale market, due to additional internal generation and reduced kilowatt-hour demand from retail customers, 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. Overall, electric sales revenues in the second quarter of 2002 showed an increase of $57.3 million, compared to the same period last year, due to a firming economy, warmer weather in June and increased sales to the wholesale market. The first half of 2002 reflected a decrease of $78.5 million, compared to the first six months of last year, principally due to the weak economic environment and customer choice in Ohio including transition incentives. Other Sales Other sales revenues declined by $47.0 million in the second quarter and $233.0 million in the first six 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 revenues were the primary factors contributing to the lower revenues. Reduced gas revenues resulted from lower prices, which were offset in part by higher sales volumes. Despite lower gas prices, gross margins for gas sales improved in 2002 (see Expenses). Reduced revenues from the facilities services group also contributed to the decrease in other sales revenue in the second quarter and year-to-date periods of 2002, compared to the same periods of 2001. Expenses Total expenses increased $863.8 million in the second quarter and $1,571.1 million in the first six months of 2002 compared to the corresponding periods of 2001, including $985.6 million and $1,965.3 million of incremental expenses related to the former GPU companies, respectively. For the pre-merger companies, total expenses decreased by $59.9 million in the second quarter and $282.0 million in the first half of 2002, compared to the same periods of 2001. Sources of changes in pre-merger and post-merger companies' expenses in the second quarter and first six months of 2002, compared to the prior year, are summarized in the following table: Sources of Expense Changes -------------------------- Increase (Decrease) Periods Ending June 30, 2002 ---------------------------- 3 Months 6 Months ---------- ----------- (In millions) Pre-Merger Companies: Fuel and purchased power.............. $ 35.0 $ (16.2) Purchased gas......................... (27.6) (174.1) Other operating expenses.............. (43.6) (10.0) Depreciation and amortization......... (43.1) (104.7) General taxes......................... 19.4 23.0 ------ -------- Total Pre-Merger Companies............ (59.9) (282.0) Former GPU Companies.................... 985.6 1,965.3 Intercompany Expenses................... (61.9) (112.2) ------ -------- Net Expense Increase.................... $863.8 $1,571.1 ====== ======== The following comparisons reflect variances for the pre-merger companies only, excluding the incremental expenses for the former GPU companies in the second quarter and first half of 2002. Fuel and purchased power costs increased $35.0 million in the second quarter but declined by $16.2 million during the first six months of 2002, compared to the same periods of 2001. Fuel expense increased in both the second quarter and first six months of 2002 ($34.5 million and $60.1 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 2002. An extended outage at the Davis-Besse nuclear plant (see Supply Plan) contributed to declines in nuclear production of 16.6% and 9.8% in the second quarter and year-to-date periods of 2002 from the same periods in 2001. Fossil plant production increased 27.3% and 21.7% in the second quarter and first six months of 2002, compared to the same periods of 2001. Overall, internal generation was approximately 8% higher in both the second quarter and first six months of 2002 than the corresponding periods of 2001. Purchased power costs were nearly unchanged in the second quarter and $76.3 million 17 lower in the first six months of 2002, compared to the same periods last year. Both periods benefited from lower unit costs for purchased power; however, increased volume requirements resulting in part from the Davis-Besse unplanned extended outage substantially offset the effect of lower costs in the second quarter of 2002. Declining gas prices resulted in reductions to purchased gas costs of $27.6 million in the second quarter and $174.1 million for the first six months of 2002, compared to the same periods of 2001 - despite an increase in gas volumes purchased. The gross margins on gas sales improved by $12.6 million in the second quarter and $32.5 million in the first six months of 2002 from the same periods last year. Other operating costs decreased by $43.6 million in the second quarter of 2002, compared to the same period of 2001. Higher expenses associated with the extended outage at the Davis-Besse nuclear plant (see Supply Plan) were more than offset by lower costs for the fossil plants. The elimination of coal trading activities in the second half of 2001 was the largest factor ($44.5 million) reducing other operating costs in the second quarter of 2002, compared to the second quarter of 2001. The decrease in other operating costs for the six-month period reflects several factors: elimination of coal trading ($88.1 million), reduced facilities service business ($24.0 million), and lower outage related fossil plant expenditures ($35.6 million). Those reductions were offset in part by additional costs related to nuclear refueling and unplanned outages ($54.7 million) and several one-time factors ($78.2 million) in 2002, including: o A $30.4 million equity investment write-off related to a bankruptcy o An $18.1 million mark-to-market adjustment of a long-term purchased power contract resulting from the update of a model-based long-term electricity price forecast. o A charge of $17.1 million related to a generation project opportunity that FirstEnergy decided not to pursue o Impairment of certain telecommunication investments totaling $10.1 million ($12.6 million including former GPU investments) Charges for depreciation and amortization decreased $43.1 million in the second quarter and $104.7 million in the first six months of 2002 from the corresponding periods last year. These decreases resulted from several factors including: 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 second quarter and year-to-date periods of 2001 totaled $14.0 million and $28.0 million, respectively. General taxes increased $19.4 million in the second quarter and $23.0 million in the first six months of 2002 from the same periods in 2001. These increases were due in large part to the successful resolution of certain property tax issues in the second quarter of 2001 resulting in a one-time benefit of $15 million in that quarter. Additional property taxes partially offset by reductions related to the Ohio restructuring accounted for the remaining net increase in the second quarter and first six months of 2002, compared to the same periods last year. Net Interest Charges Net interest charges increased $129.3 million in the second quarter and $262.8 million in the first half of 2002, compared to the same periods of 2001. These increases included interest of $68.0 million in the second quarter and $141.9 million in the first six 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 $8.0 million in the second quarter and $9.8 million in the first six months of 2002 from the corresponding periods in 2001. Redemption and refinancing activities completed in the first six months of 2002 totaled $446.1 million and are expected to result in annualized savings of $32.1 million (interest rate swap effect not included - see Market Risk Information, New Interest Rate Swap Agreements). 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 year-to-date net income in 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. 18 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 $272.9 million in the second quarter of 2002 and $470.8 million in the first half of 2002, compared to $159.2 million and $281.8 million in the corresponding periods of 2001. Excluding results of the former GPU companies, net income increased by $25.9 million to $185.2 million in the second quarter and by $28.7 million to $310.5 million in the first six months of 2002. The factors contributing to the increase in pre-merger net income are summarized in the following table: Regulated Services ------------------ Increase (Decrease) Periods Ending June 30, 2002 ---------------------------- 3 Months 6 Months -------- -------- (In millions) Revenues.................................... $(52.0) $(260.2) Expenses.................................... (77.5) (271.5) ------ ------- Income Before Interest and Income Taxes..... 25.5 11.3 Net interest charges........................ (21.4) (51.2) Income taxes................................ 21.0 33.8 ------ ------- Net Income Increase......................... $ 25.9 $ 28.7 ====== ======= Lower generation sales and additional transition plan incentive credits combined to reduce revenues in the second quarter of 2002 from the same period in 2001. In the first six months of 2002, retail generation sales and distribution throughput were both down, reflecting the combined influences 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 second quarter and first half of 2002 than the corresponding periods of 2001, primarily due to lower purchased power, depreciation and amortization, and other operating expenses. Lower generation sales reduced the need to purchase power from FES, which contributed to a $31.5 million expense decrease in the second quarter and a $121.4 million decrease in the first six months of 2002, compared to the same periods last year. Depreciation and amortization declined by $48.2 million in the second quarter and $114.0 million in the first half 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 $13.7 million in the second quarter and $48.7 million in the first six months of 2002, compared to the same periods last year. Reduced expenses from jobbing and contracting work lowered other operating expenses by approximately $16.6 million in the second quarter and first half of 2002, compared to the same periods of 2001. Net interest charges in the second quarter and year-to-date periods of 2002 decreased by $21.4 million and $51.2 million, respectively, from the corresponding periods of 2001, reflecting the impact of net debt and preferred stock redemptions and refinancings. Competitive Services Net income was $6.4 million in the second quarter of 2002, compared to a net loss of $17.0 million in the same period of 2001. For the first six months of 2002 the net loss increased to $53.3 million ($14.4 million excluding one-time items) from $48.8 million in the first half of last year. Excluding results of the former GPU companies, net income was $5.7 million in the second quarter, and the net loss was $55.2 million in the first six months of 2002. The factors contributing to the changes in pre-merger earnings are summarized in the following table: 19 Competitive Services -------------------- Increase (Decrease) Periods Ending June 30, 2002 ---------------------------- 3 Months 6 Months -------- -------- (In millions) Revenues..................................... $ 20.4 $(164.5) Expenses..................................... (20.4) (147.6) ------ ------- Income Before Interest and Income Taxes...... 40.8 (16.9) Net interest charges......................... 2.4 8.3 Income taxes................................. 15.7 (10.3) Cumulative effect of a change in accounting.. -- 8.5 ------ ------- Net Income Increase (Decrease)............... $ 22.7 $ (6.4) ====== ======= 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 $62.9 million in the second quarter and $124.3 million in the first six months of 2002, compared to the prior year. FES retail electric sales revenue contributed $8.2 million to the increase in the second quarter of 2002 and was nearly unchanged over the first half of 2002. As a result, electricity sales to non-affiliates increased $71.1 million in the second quarter and $123.4 million in the first half of 2002 from the same periods last year. In the second quarter, this increase was partially offset by reduced sales to regulated affiliates reflecting the impact of shopping by Ohio customers for alternative power providers, reduced natural gas revenues resulting from lower prices and less revenue from the facilities services group, resulting in a net $20.4 million increase. In the year-to-date period, additional electricity sales to non-affiliates were more than offset by lower sales to regulated affiliates, reduced gas revenues and lower revenues from the facilities services group. Expenses decreased by $20.4 million in the second quarter and $147.6 million in the first six months of 2002, compared to the same periods of 2001. The decrease in second quarter expenses was primarily attributable to lower purchased gas costs reflecting reduced unit costs, lower operating costs and reduced expenses from the facilities service group due to reduced business activity. Other operating costs and purchased power costs were lower despite incremental expenses ($12.3 million other operating costs and $33.6 million of replacement purchased power costs) related to the extended outage at Davis-Besse (see Supply Plan). Partially offsetting these lower expenses was additional fuel expense resulting from additional internal generation and an increased mix of higher-cost fossil generation. Higher unit costs for coal consumed in 2002 also added to the increase in fuel expense. Reduced expenses for the first six months of 2002 primarily reflect lower purchased gas and purchased power costs, partially offset by higher fuel costs and other operating expenses. Several one-time charges (see Expenses) increased other operating expenses in the first six months of 2002 by $65.6 million. 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 half of 2002, capital requirements for property additions and capital leases are expected to be about $585 million, including $34 million for nuclear fuel. These capital requirements include $60 million of additional repair costs for the unplanned extended outage at the Davis-Besse nuclear plant (see Supply Plan). FirstEnergy has additional cash requirements of approximately $615.4 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2002. FirstEnergy also anticipates optional preferred stock redemptions during the last half of 2002 totaling about $145.0 million. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Mandatory and optional redemptions and refinancings (excluding a fixed-to-floating rate conversion - discussed below) over the remainder of the year are expected to reduce interest and preferred dividends by approximately $62.7 million annually. The sale of a 79.9% interest in Avon to Aquila on May 8, 2002, resulted in the elimination from FirstEnergy's balance sheet of approximately $1.7 billion of Avon's debt, which is non-recourse to FirstEnergy. In total, FirstEnergy expects to reduce debt and preferred stock by about $760.4 million in the last two quarters of 2002. JCP&L issued $320 million of transition bonds in June 2002, which securitize recovery of certain stranded costs. Net proceeds from the issuance will be used to redeem higher cost debt and preferred stock during the second half of 2002. During the second quarter of 2002, FirstEnergy entered into five interest rate swap agreements designed to exchange fixed interest rate obligations associated with existing long-term debt for variable interest rate payments. The agreements effectively converted $668.5 million of FirstEnergy's debt from fixed rate to floating rate. Two additional interest rate swaps were completed in July 2002 for debt with a principal value of $325 million (see Market Risk Information). 20 As of June 30, 2002, FirstEnergy and its subsidiaries had about $359.1 million of cash and temporary investments and $644.8 million of short-term indebtedness. Available borrowings included $1.035 billion from unused revolving lines of credit and $76 million from unused bank facilities. 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 $2.0 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds, as of June 30, 2002. JCP&L, Met-Ed and Penelec had the capability to issue $816 million of additional senior notes based upon FMB collateral, as of June 30, 2002. Based upon applicable charter earnings coverage tests through June 30, 2002, OE, Penn, TE and JCP&L could issue $7.6 billion of preferred stock (assuming no additional debt was issued). CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock. On July 31, 2002, Fitch revised its rating outlook for FirstEnergy, CEI and TE securities to negative from stable. The revised outlook reflects the adverse impact of the unplanned outage at the Davis-Besse Plant and Fitch's judgment at that time about NRG's financial ability to consummate the purchase of four power plants from FirstEnergy and Fitch's expectation of subsequent delay in debt reduction. On August 1, 2002, the Standard & Poor's Utilities Ratings Team (S&P) concluded that while NRG's liquidity position added uncertainty to its sale of power plants to NRG, FirstEnergy's ratings would not be affected. S&P found FirstEnergy cash flows sufficiently stable to support a continued (although delayed) program of debt and preferred stock redemption. S&P noted that it would continue to closely monitor FirstEnergy's progress on various initiatives. 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. New Interest Rate Swap Agreements --------------------------------- During the second quarter of 2002, FirstEnergy entered into five interest rate swap agreements and two additional interest rate swap agreements were subsequently completed in July 2002. The transactions collectively increased the proportion of variable rate obligations in FirstEnergy's debt portfolio from 14% at the beginning of 2002 to a level of approximately 22% expected by year end, with the variable interest rate payments based on the six month LIBOR rate plus a fixed spread. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options and interest payment dates match those of the underlying obligations. The following summarizes the principal characteristics of the new swap agreements. Debt Hedged ----------------- Fixed Principal June 30, 2002 Issuer Coupon Amount Swap Fair Value ------ ------ --------- ------------- ($ millions) Completed in June 2002 ---------------------- JCP&L 6.750% $150.0 $ (1.5) CEI 9.000% 150.0 (4.0) OE 7.625% 75.0 (2.5) OE 7.875% 93.5 (2.4) FE 5.500% 200.0 (0.3) ------ ------ 668.5 $(10.7) ====== Completed in July 2002 ---------------------- JCP&L 7.500% 125.0 FE 5.500% 200.0 ------ Total $993.5 ====== The average fixed rate of the hedged debt above is 6.85%, compared to an average variable rate of 3.16% to be paid by FirstEnergy under the swap agreements. FirstEnergy accrues interest on the hedged debt at the lower, variable rate. In the event FirstEnergy or its swap counterparties terminate the transactions before the underlying debt issues mature, payments are made or received equal to the fair value of the swaps at that time and are amortized over the remaining life of the hedged debt. 21 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. The change in the fair value of commodity derivative contracts related to energy production during the second 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 March 31, 2002................. $ 25.6 New contract value when entered............................ 0.1 Decrease in value of existing contracts.................... (22.9) Change in techniques/assumptions........................... -- Settled contracts.......................................... (0.8) ------ Outstanding net asset as of June 30, 2002................ $ 2.0 ====== * Does not include $1.1 million of derivative contract fair value increase, as of June 30, 2002, representing FirstEnergy's 50% share of Great Lakes Energy Partners, LLC 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: Source of Information - Fair Value by Contract Year --------------------------------------------------- 2002* 2003 2004 Thereafter Total ----- ---- ---- ---------- ----- (In millions) Prices actively quoted......... $(15.5) $(0.6) $(9.0) $ -- $(25.1) Prices based on models**....... -- -- -- 27.1 27.1 --------------------------------------------- Total...................... $(15.5) $(0.6) $(9.0) $27.1 $ 2.0 ============================================= * For the last half of 2002. ** Includes $22.2 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 June 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 $5.4 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 does not reach 20% for any consecutive twelve-month period by December 31, 2005 - the end of the market development period. As of June 30, 2002, the annualized customer-switching rate had reduced FirstEnergy's risk of not recovering transition costs to approximately $31 million. FirstEnergy began accepting customer applications for switching to alternative suppliers on December 8, 2000; as of June 30, 2002 its Ohio EUOC had been notified that over 725,000 of their customers requested generation services from other authorized suppliers, including FES, a wholly owned subsidiary. 22 New Jersey Under New Jersey transition legislation, all electric distribution companies in that state are required to file rate cases by August 1, 2002. On August 1, 2002, FirstEnergy submitted two rate filings for JCP&L with the New Jersey Board of Public Utilities (NJBPU). The first related to base electric rates (Delivery Charge Filing). The second was a request to recover deferred costs (Deferral Filing) primarily associated with mandated purchase-power contracts with non-utility generators (NUGs) - which produce power at prices that exceed wholesale market prices - and providing Basic Generation Service (BGS) to customers in excess of the state's generation rate cap. The new rate structure, when approved, becomes effective on August 1, 2003. Delivery Charge Filing - The delivery charge filing includes recovery of JCP&L's distribution, transmission, customer service, administrative and general costs, along with taxes and some assessment fees. FirstEnergy is requesting a decrease in the JCP&L delivery charge of $11 million, or a 0.6% rate reduction. The filing uses calendar year 2002 as the test year and is based on a net rate base value of $2.1 billion and allowed return on common equity of 12%. The December 31, 2001 capital structure used in the filing has been modified to eliminate purchase accounting adjustments from the merger of FirstEnergy and GPU, Inc. and to remove a pre-merger $300 million deferred balance write-off required by the NJBPU merger approval order (See Deferral Filing). The modified capital structure is comparable to JCP&L's pre-merger capital structure. Deferral Filing - The deferral filing addresses the current Market Transition Charge (MTC) and the Societal Benefits Charge (SBC), which were confirmed by a 2001 rate order. The combined effect of JCP&L's MTC and SBC requests would result in a 2.8% rate increase with securitization of a deferred balance; if securitization is not available, there would be an additional 6.5% increase with a four-year amortization of the deferred balance. JCP&L was authorized to defer energy-related costs incurred in providing BGS to non-shopping retail customers and costs incurred under NUG agreements and purchased power agreements that exceeded the amounts collected under the current BGS and MTC rates. Additionally, in 2001, JCP&L wrote off $300 million of deferred costs upon receipt of the NJBPU merger approval order, in order to ensure that customers receive the benefit of future merger savings. This amount is not included in the requested deferred cost recovery. JCP&L's filing proposes to recover the MTC deferred balance through a securitization transaction involving the issuance of transition bonds in a principal amount equal to the projected July 31, 2003 MTC deferred balance of $684 million. The transition bond-related rate increase would be approximately $69 million per year, or a 3.5% increase. An alternative to securitization of the deferred balance would be to recover the deferred balance over a four-year amortization period with interest. This alternative approach would require an MTC rate increase of $195 million or an increase of 10%. JCP&L's securitization proposal minimizes the required customer rate increase. Stranded cost securitization would create a transition bond charge (TBC) which would be the revenue collection mechanism for the transition bond principal and interest payments. In June 2002, JCP&L sold $320 million principal amount of transition bonds to securitize its net investment in the Oyster Creek nuclear generating facility. The TBC was offset by a corresponding reduction in the MTC since the stranded Oyster Creek investment was initially being amortized through the MTC. Securitization of the deferred energy-related cost balance would require an increase in the TBC. The 2001 rate order confirmed the establishment of the SBC to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation. JCP&L's request would reduce the SBC by $14 million, or a 0.7% rate decrease. Sale of Power Plants -------------------- On November 29, 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). By constructing peaking units and selling these larger generating plants, FirstEnergy is reshaping its generating capability to more efficiently meet the needs of its target market. 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. As a result, FirstEnergy will pursue opportunities with other parties who have expressed interest in purchasing the plants. FirstEnergy believes that an agreement can be reached with another buyer on a timely basis and that no impairment of these assets is appropriate. 23 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 June 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 by November 6, 2002. Potential investors recently retained a financial advisor to assist in the due diligence process and FirstEnergy expects that preliminary negotiations with those investors may be completed in the third quarter of 2002. If FirstEnergy has not completed the sale of all of its interest in Emdersa or has not reached a definitive agreement to sell such interest by November 6, 2002, 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 by November 6, 2002) would be reflected on FirstEnergy's Consolidated Statement of Income as a "Cumulative Effect of a Change in Accounting". As of June 30, 2002, that adjustment would have reduced FirstEnergy's net income by approximately $95 million ($0.33 per share of common stock). Supply Plan ----------- 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. On May 23, 2002, FirstEnergy purchased an unused reactor vessel head from Consumers Energy's Midland Nuclear Plant - similar in design to the Davis-Besse Plant. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant changes in senior and mid-level managers at the plant and in its corporate nuclear organization. It has also established an independent oversight panel consisting of industry experts to assist in Davis-Besse restart efforts and to provide advice regarding the safe return of Davis-Besse to service. FirstEnergy expects to complete refurbishment and installation of the replacement reactor head as well as any other work related to restart of the plant in the fourth quarter of this year. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. The estimated, incremental costs (capital and expense) associated with the extended Davis-Besse outage in 2002 are: Incremental Costs of Davis-Besse Extended Outage ------------------------------------------------ Expenditure Range ----------------- (In millions) Replace reactor vessel head (principally capital expenditures). $55-$75 Primarily operating expenses (pre-tax): Additional maintenance (including acceleration of programs).... $50-$70 Replacement power for July and August 2002..................... $40 Replacement power for September through December .............. $40-$60 FirstEnergy has fully hedged its on-peak replacement energy supply for Davis-Besse through the end of 2002. FirstEnergy's fossil units performed very well in the first half of 2002, more than replaced the reduced nuclear output. Although FirstEnergy expects to return Davis-Besse to service before the end of the year, it has made on-peak power purchases for delivery in early 2003 to meet a portion of FirstEnergy's incremental power needs if the Davis-Besse restart date is delayed. FirstEnergy continues to enter into power contracts to cover its "provider of last resort" obligations for the 2003-2005 period. Market conditions are currently relatively favorable, therefore minimizing FirstEnergy's exposure to the commodity market and reducing potential negative impacts related to the pending appeal to the Pennsylvania Supreme Court with respect to the Met-Ed and Penelec deferred energy mechanism. FirstEnergy is now over 90% hedged for the projected 2003 summer peak and approximately 85% hedged for the projected 2004 and 2005 summer peak loads. 24 Environmental Matters --------------------- Various environmental liabilities have been recognized on the Consolidated Balance Sheet as of June 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. 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. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. 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 $57.3 million as of June 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. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill, which must be reviewed for impairment at least annually. FirstEnergy's most recent review was completed in June 2002. The results of that review indicate that no impairment of goodwill is appropriate. As of June 30, 2002, FirstEnergy had $5.6 billion of goodwill that primarily relates to its regulated services segment. 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 -- $8.6 billion as of June 30, 2002. FirstEnergy 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. 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. 25 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 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 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 will 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 second half of 2002. 26
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Six Months Ended June 30, June 30, --------------------- ------------------------ 2002 2001 2002 2001 -------- -------- ---------- ---------- (In thousands) OPERATING REVENUES........................................ $744,550 $744,712 $1,452,349 $1,527,815 -------- -------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel................................................... 15,129 13,408 29,419 27,554 Purchased power........................................ 213,172 237,795 454,651 544,212 Nuclear operating costs................................ 80,700 76,987 175,934 169,232 Other operating costs.................................. 78,497 79,716 158,108 160,672 -------- -------- ---------- ---------- Total operation and maintenance expenses............. 387,498 407,906 818,112 901,670 Provision for depreciation and amortization............ 91,521 104,205 183,651 221,161 General taxes.......................................... 42,524 26,133 87,900 71,087 Income taxes........................................... 84,403 68,540 127,018 107,141 -------- -------- ---------- ---------- Total operating expenses and taxes................... 605,946 606,784 1,216,681 1,301,059 -------- -------- ---------- ---------- OPERATING INCOME.......................................... 138,604 137,928 235,668 226,756 OTHER INCOME.............................................. 15,087 17,821 15,599 30,186 -------- -------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES........................ 153,691 155,749 251,267 256,942 -------- -------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt............................. 30,312 39,527 63,385 78,914 Allowance for borrowed funds used during construction and capitalized interest................ (883) 1,612 (1,504) (1,306) Other interest expense................................. 2,801 5,806 7,948 12,718 Subsidiaries' preferred stock dividend requirements.... 3,626 3,626 7,252 7,252 -------- -------- ---------- ---------- Net interest charges................................. 35,856 50,571 77,081 97,578 -------- -------- ---------- ---------- NET INCOME................................................ 117,835 105,178 174,186 159,364 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,597 2,702 5,193 5,404 -------- -------- ---------- ---------- EARNINGS ON COMMON STOCK.................................. $115,238 $102,476 $ 168,993 $ 153,960 ======== ======== ========== ========== The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.
27
OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, 2002 2001 ----------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................. $5,000,153 $4,979,807 Less--Accumulated provision for depreciation............................... 2,507,148 2,461,972 ---------- ---------- 2,493,005 2,517,835 ---------- ---------- Construction work in progress- Electric plant........................................................... 98,938 87,061 Nuclear fuel............................................................. 816 11,822 ---------- ---------- 99,754 98,883 ---------- ---------- 2,592,759 2,616,718 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: PNBV Capital Trust......................................................... 416,152 429,040 Letter of credit collateralization......................................... 277,763 277,763 Nuclear plant decommissioning trusts....................................... 295,381 277,337 Long-term notes receivable from associated companies....................... 504,439 505,028 Other...................................................................... 308,084 303,409 ---------- ---------- 1,801,819 1,792,577 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents.................................................. 24,139 4,588 Receivables- Customers (less accumulated provisions of $4,692,000 and $4,522,000, respectively, for uncollectible accounts).................. 341,330 311,744 Associated companies..................................................... 470,053 523,884 Other (less accumulated provisions of $1,000,000 for uncollectible accounts at both dates)................................................ 33,053 41,611 Notes receivable from associated companies................................. 243,961 108,593 Materials and supplies, at average cost- Owned.................................................................... 55,072 53,900 Under consignment........................................................ 17,573 13,945 Other...................................................................... 19,268 50,541 ---------- ---------- 1,204,449 1,108,806 ---------- ---------- DEFERRED CHARGES: Regulatory assets.......................................................... 2,130,457 2,234,227 Other...................................................................... 165,262 163,625 ---------- ---------- 2,295,719 2,397,852 ---------- ---------- $7,894,746 $7,915,953 ========== ==========
28
OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 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........................................................ 640,065 572,272 ---------- ---------- Total common stockholder's equity.................................... 2,738,794 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............................................................. 1,483,805 1,614,996 ---------- ---------- 4,336,919 4,620,317 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock....................... 700,837 576,962 Short-term borrowings- Associated companies..................................................... 42,538 26,076 Other.................................................................... 177,131 219,750 Accounts payable- Associated companies..................................................... 95,645 110,784 Other.................................................................... 15,497 19,819 Accrued taxes.............................................................. 465,091 258,831 Accrued interest........................................................... 31,090 33,053 Other...................................................................... 64,160 63,140 ---------- ---------- 1,591,989 1,308,415 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes.......................................... 1,125,037 1,175,395 Accumulated deferred investment tax credits................................ 92,829 99,193 Nuclear plant decommissioning costs........................................ 294,544 276,500 Other postretirement benefits.............................................. 169,629 166,594 Other...................................................................... 283,799 269,539 ---------- ---------- 1,965,838 1,987,221 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)............................ ---------- ---------- $7,894,746 $7,915,953 ========== ========== The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.
29
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ---------------------- ---------------------- 2002 2001 2002 2001 -------- --------- -------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $117,835 $ 105,178 $174,186 $ 159,364 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 91,521 104,205 183,651 221,161 Nuclear fuel and lease amortization................ 12,133 11,920 23,535 23,677 Deferred income taxes, net......................... (8,886) (22,160) (22,056) (42,562) Investment tax credits, net........................ (3,762) (3,341) (7,535) (6,694) Receivables........................................ (31,345) (137,091) 32,803 (194,795) Materials and supplies............................. (3,158) 914 (4,800) 54,060 Accounts payable................................... (1,166) 35,497 (19,461) (52,684) Accrued taxes ..................................... 149,376 (20,063) 206,260 18,211 Other.............................................. (29,119) (54,008) (5,643) (46,627) -------- --------- -------- --------- Net cash provided from operating activities...... 293,429 21,051 560,940 133,111 -------- --------- -------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... -- 249,042 -- 249,542 Redemptions and Repayments- Long-term debt....................................... 244,179 30,560 228,741 37,710 Short-term borrowings, net........................... 66,464 21,062 26,158 15,447 Dividend Payments- Common stock......................................... -- -- 101,200 37,300 Preferred stock...................................... 2,596 2,706 5,193 5,404 -------- --------- -------- --------- Net cash used for (provided from) financing activities 313,239 (194,714) 361,292 (153,681) -------- --------- -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... 25,377 15,608 55,721 41,006 Loans to associated companies.......................... -- 136,257 135,325 311,829 Loan payments from associated companies................ (3,402) (506) (546) (506) Sale of assets to associated companies................. -- (33,002) -- (154,596) Other.................................................. (8,431) (4,567) (10,403) (6,046) -------- --------- -------- --------- Net cash used for investing activities........... 13,544 113,790 180,097 191,687 -------- --------- -------- --------- Net increase (decrease) in cash and cash equivalents...... (33,354) 101,975 19,551 95,105 Cash and cash equivalents at beginning of period.......... 57,493 11,399 4,588 18,269 -------- --------- -------- --------- Cash and cash equivalents at end of period................ $ 24,139 $ 113,374 $ 24,139 $ 113,374 ======== ========= ======== ========= The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.
30 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 June 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and six-month periods ended June 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 August 8, 2002 31 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 were nearly unchanged in the second quarter and decreased $75.5 million or 4.9% in the first half 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, reduced revenues from wholesale customers and weather. While retail kilowatt-hour sales declined by 3.3% in the second quarter of 2002, compared to the second quarter of 2001, favorable price variances resulting from a change in sales mix resulted in a relatively small reduction in generation sales revenue. During the first six months of 2002, however, kilowatt-hour sales declined in all customer sectors - residential, commercial and industrial - resulting in a 12.1% reduction overall and reduced operating revenues by $41.0 million. 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 19.0% in the second quarter of 2002 from 13.7% in the same period last year. During the first six months of 2002, OE's share of electric generation sales in its franchise areas decreased by 9.5 percentage points, compared to the same period of 2001. Distribution deliveries increased 3.0% in the second quarter of 2002, which increased revenues from electricity throughput by $14.0 million, compared with the second quarter of 2001. The second quarter of 2002 benefited from a slight pick up in economic activity and warmer June weather. Despite the stronger second quarter performance, distribution deliveries and revenues were lower in the first six months of 2002, compared to the same period last year, declining by 2.0% and $7.0 million, respectively, primarily due to the weaker economic environment earlier in the year. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, further reduced operating revenues in the second quarter and first six months of 2002, compared to the corresponding periods of 2001 - reducing comparable revenues by $6.7 million and $16.6 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 were also lower in both the second quarter and year-to-date periods of 2002, compared to the same periods 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 second quarter and first six 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 June 30, 2002 ---------------------------- 3 Months 6 Months -------- -------- (In millions) Retail: Generation sales......................... $(1.0) $(41.0) Distribution deliveries.................. 14.0 (7.0) Increased shopping incentives............ (6.7) (16.6) ----- ------ Total Retail............................. 6.3 (64.6) Wholesale.................................. (3.6) (10.2) Other.................................... (2.9) (0.7) ----- ------ Net Decrease in Operating Revenue.......... $(0.2) $(75.5) ===== ====== 32 Operating Expenses and Taxes Total operating expenses and taxes were slightly lower in the second quarter and declined $84.4 million in the first six months of 2002 from the corresponding periods of 2001. Purchased power costs decreased $24.6 million in the second quarter and $89.6 million in the first six 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 $3.7 million in the second quarter and $6.7 million in the first half of 2002 from the same periods in 2001. The six-month increase reflected additional amounts related to the first quarter 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. Charges for depreciation and amortization decreased by $12.7 million in the second quarter and $37.5 million in the first six months of 2002, compared to the same periods last year. These decreases primarily resulted from higher shopping incentive deferrals and tax-related deferrals under OE's transition plan in 2002. General taxes increased by $16.4 million in the second quarter and $16.8 million in the first six months of 2002 from the same periods in 2001, due in large part to the successful resolution of certain property tax issues in the second quarter of 2001. This resulted in a one-time benefit of $15 million in the second quarter of 2001. Other Income Other income decreased $2.7 million in the second quarter and $14.6 million in the first half of 2002 from the corresponding periods of 2001. Reduced interest income was the principal factor in the second quarter decrease. Most 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 $14.7 million in the second quarter and $20.5 million in the first six months of 2002, compared to the same periods last year, primarily due to debt redemption and refinancing activities. During the first six months of 2002, maturing debt redemptions totaled $140.1 million and will result in annualized savings of $11.5 million. Capital Resources and Liquidity ------------------------------- The OE Companies have continuing cash requirements for planned capital expenditures and maturing debt. During the last two quarters of 2002, capital requirements for property additions and capital leases are expected to be about $98 million, including $20 million for nuclear fuel. The OE Companies also have sinking fund requirements for preferred stock and maturing long-term debt of $182.6 million and optional preferred stock redemptions of $220 million during the remainder of 2002. These requirements are expected to be satisfied from internal cash and/or short-term credit arrangements. As of June 30, 2002, the OE Companies had about $268.1 million of cash and temporary investments and $219.7 million of short-term indebtedness. Their available borrowing capability included $250.0 million from unused revolving lines of credit and $26 million from unused bank facilities. As of June 30, 2002, the OE Companies had the capability to issue up to $1.5 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, $2.6 billion of preferred stock (assuming no additional debt was issued) could be issued based on earnings through the second quarter of 2002. 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 does not reach 20% for any consecutive twelve-month period by December 31, 2005 - the end of the market development period. As of June 30, 2002, the annualized customer-switching rate essentially reduced OE's risk of not recovering transition costs to approximately $31 million. OE began accepting customer applications for switching to alternative suppliers on December 8, 2000 and has received notifications as of June 30, 2002 that over 220,000 of its customers requested generation services from other authorized suppliers. 33 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 OE's financial results. All of OE'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. OE's 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 June 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. As disclosed in Note 4 - Regulatory Matters - Ohio, OE's full recovery of transition costs is dependent on achieving 20% shopping levels in any twelve-month period by 2005. 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 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 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 will be recorded if the cost to settle the retirement obligation differs from the carrying amount. The OE Companies have identified various applicable legal obligations as defined under the new standard and expect to complete an analysis of their financial impact in the second half of 2002. 34
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ---------------------- ----------------------- 2002 2001 2002 2001 -------- -------- -------- ---------- (In thousands) OPERATING REVENUES........................................ $462,874 $498,766 $887,851 $1,015,183 -------- -------- -------- ---------- OPERATING EXPENSES AND TAXES: Fuel................................................... 15,088 16,888 32,358 34,753 Purchased power........................................ 118,458 193,590 257,894 408,095 Nuclear operating costs................................ 38,785 28,679 110,202 78,629 Other operating costs.................................. 68,353 72,396 135,200 150,699 -------- -------- -------- ---------- Total operation and maintenance expenses........... 240,684 311,553 535,654 672,176 Provision for depreciation and amortization............ 28,333 52,964 56,804 109,728 General taxes.......................................... 36,493 34,080 75,239 71,950 Income taxes........................................... 44,610 21,579 52,078 29,294 -------- -------- -------- ---------- Total operating expenses and taxes................. 350,120 420,176 719,775 883,148 -------- -------- -------- ---------- OPERATING INCOME.......................................... 112,754 78,590 168,076 132,035 OTHER INCOME.............................................. 3,356 1,138 8,597 5,558 -------- -------- -------- ---------- INCOME BEFORE NET INTEREST CHARGES........................ 116,110 79,728 176,673 137,593 -------- -------- -------- ---------- NET INTEREST CHARGES: Interest on long-term debt............................. 45,372 48,317 92,367 96,602 Allowance for borrowed funds used during construction.. (747) (216) (1,496) (1,073) Other interest expense (credit)........................ (125) (879) (654) (2,075) Subsidiaries' preferred stock dividend requirements.... 2,250 -- 4,400 -- -------- -------- -------- ---------- Net interest charges............................... 46,750 47,222 94,617 93,454 -------- -------- -------- ---------- NET INCOME................................................ 69,360 32,506 82,056 44,139 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 3,054 6,561 11,310 13,122 -------- -------- -------- ---------- EARNINGS ON COMMON STOCK.................................. $ 66,306 $ 25,945 $ 70,746 $ 31,017 ======== ======== ======== ========== The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.
35
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, 2002 2001 ---------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $4,081,483 $4,071,134 Less--Accumulated provision for depreciation.............................. 1,771,704 1,725,727 ---------- ---------- 2,309,779 2,345,407 ---------- ---------- Construction work in progress- Electric plant.......................................................... 94,511 66,266 Nuclear fuel............................................................ 29,033 21,712 ---------- ---------- 123,544 87,978 ---------- ---------- 2,433,323 2,433,385 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust................................................ 448,149 475,543 Nuclear plant decommissioning trusts...................................... 226,910 211,605 Long-term notes receivable from associated companies...................... 103,205 103,425 Other..................................................................... 20,937 24,611 ---------- ---------- 799,201 815,184 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 290 296 Receivables- Customers............................................................... 14,272 17,706 Associated companies.................................................... 56,035 75,113 Other (less accumulated provisions of $1,015,000 for uncollectible accounts at both dates)............................................... 153,885 99,716 Notes receivable from associated companies................................ 430 415 Materials and supplies, at average cost- Owned................................................................... 18,431 20,230 Under consignment....................................................... 33,538 28,533 Other..................................................................... 2,023 31,634 ---------- ---------- 278,904 273,643 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 907,948 874,488 Goodwill.................................................................. 1,370,639 1,370,639 Other..................................................................... 96,880 88,767 ---------- ---------- 2,375,467 2,333,894 ---------- ---------- $5,886,895 $5,856,106 ========== ==========
36
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 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......................................... $ 931,962 $ 931,962 Retained earnings....................................................... 220,863 150,183 ---------- ---------- Total common stockholder's equity................................... 1,152,825 1,082,145 Preferred stock- Not subject to mandatory redemption..................................... 96,404 141,475 Subject to mandatory redemption......................................... 6,129 6,288 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures......... 100,000 100,000 Long-term debt............................................................ 2,037,118 2,156,322 ---------- ---------- 3,392,476 3,486,230 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 589,868 526,630 Accounts payable- Associated companies.................................................... 121,915 81,463 Other................................................................... 16,259 30,332 Notes payable to associated companies..................................... 124,367 97,704 Accrued taxes............................................................. 142,505 129,830 Accrued interest.......................................................... 56,763 57,101 Other..................................................................... 46,236 60,664 ---------- ---------- 1,097,913 983,724 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 649,647 637,339 Accumulated deferred investment tax credits............................... 74,156 76,187 Nuclear plant decommissioning costs....................................... 236,103 220,798 Pensions and other postretirement benefits................................ 234,079 231,365 Other..................................................................... 202,521 220,463 ---------- ---------- 1,396,506 1,386,152 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $5,886,895 $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.
37
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ----------------------- ---------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 69,360 $ 32,506 $ 82,056 $ 44,139 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 28,333 52,964 56,804 109,728 Nuclear fuel and lease amortization................ 4,794 7,070 10,784 14,114 Other amortization................................. (4,275) (4,039) (8,167) (7,672) Deferred income taxes, net......................... 5,904 4,607 13,100 4,660 Investment tax credits, net........................ (1,129) (970) (2,031) (1,939) Receivables........................................ (38,473) (60,559) (31,657) 15,060 Materials and supplies............................. (1,840) 234 (3,206) 15,557 Accounts payable................................... 8,057 8,869 26,379 (46,181) Accrued taxes...................................... 17,743 21,765 12,675 (26,704) Other.............................................. (45,522) (13,482) (26,263) (67,065) -------- -------- -------- -------- Net cash provided from operating activities...... 42,952 48,965 130,474 53,697 -------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net........................... -- 96,323 26,663 128,586 Redemptions and Repayments- Preferred stock...................................... -- 10,716 100,000 10,716 Long-term debt....................................... 96 21,264 190 29,904 Short-term borrowings, net........................... 48,821 -- -- -- Dividend Payments- Common stock......................................... -- 84,000 -- 105,800 Preferred stock...................................... 3,133 7,040 8,385 14,077 -------- -------- -------- -------- Net cash used for financing activities........... 52,050 26,697 81,912 31,911 -------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... 25,452 5,363 61,922 15,580 Loans to associated companies.......................... -- 11,117 -- 11,117 Loan payments from associated companies................ (205) (188) (205) (188) Capital trust investments.............................. (27,394) (1,071) (27,394) (16,279) Sale of assets to associated companies................. -- (11,117) -- (11,117) Other.................................................. 8,021 18,140 14,245 25,290 -------- -------- -------- -------- Net cash used for investing activities........... 5,874 22,244 48,568 24,403 -------- -------- -------- -------- Net increase (decrease) in cash and cash equivalents...... (14,972) 24 (6) (2,617) Cash and cash equivalents at beginning of period.......... 15,262 214 296 2,855 -------- -------- -------- -------- Cash and cash equivalents at end of period................ $ 290 $ 238 $ 290 $ 238 ======== ======== ======== ======== The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.
38 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 June 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and six-month periods ended June 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 August 8, 2002 39 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 $35.9 million or 7.2% in the second quarter and $127.3 million or 12.5% in the first half 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 and reduced sales to wholesale customers. Kilowatt-hour sales to generation customers decreased by 23.0% in the second quarter and 30.8% in the first six 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 27.9% in the second quarter of 2002 from 12.1% in the same period last year. During the first six months of 2002, CEI's share of electric generation sales in its franchise area decreased by 20.8 percentage points, compared to the same period of 2001. A very weak steel sector in CEI's service area also contributed significantly to the decline in kilowatt-hour sales to generation customers in both the second quarter and first six months of 2002 from the corresponding periods last year. Despite lower distribution deliveries in the second quarter of 2002, compared to the same quarter of 2001, distribution revenues increased by $5.8 million - reflecting an increase in the proportion of kilowatt-hour sales to residential customers. Sales to residential customers benefited from warmer weather in June 2002, increasing air-conditioning load, as compared to last year. Distribution deliveries and revenues were lower in the first six months of 2002, compared to the same period last year, declining 10.7% and $27.8 million, respectively, 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 second quarter and first six months of 2002, compared to the corresponding periods of 2001 - reducing comparable revenues by $10.1 million and $24.1 million, respectively. These revenue reductions are deferred for future recovery under CEI's transition plan and do not materially affect current period earnings. Revenues on sales to wholesale customers were lower in the second quarter and slightly higher in the year-to-date period of 2002, compared to the same periods last year, on lower kilowatt-hour sales in both periods. Increased revenues from kilowatt-hour sales to nonaffiliated customers in the wholesale market were more than offset by reduced revenues from FES in the second quarter of 2002. The sources of changes in operating revenues during the second quarter and first six 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 June 30, 2002 ---------------------------- 3 Months 6 Months -------- -------- (In millions) Retail: Generation sales...................... $(20.7) $ (70.9) Distribution deliveries............... 5.8 (27.8) Increased shopping incentives......... (10.1) (24.1) ------ ------- Total Retail.......................... (25.0) (122.8) Wholesale............................... (7.8) 0.8 Other................................... (3.1) (5.3) ------ ------- Net Operating Revenue Decrease.......... $(35.9) $(127.3) ====== ======= 40 Operating Expenses and Taxes Total operating expenses and taxes declined by $70.1 million in the second quarter and $163.4 million in the first six months of 2002 from the corresponding periods of 2001. Purchased power costs decreased $75.1 million in the second quarter and $150.2 million in the first six 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 $10.1 million in the second quarter and $31.6 million in the first half of 2002 from the same periods in 2001. Costs related to the extended outage at the Davis-Besse nuclear plant (see Capital Resources and Liquidity) and to a lesser extent additional operating costs at Beaver Valley Unit 2 and the Perry Plant, accounted for the increase in nuclear costs in the second quarter compared to the second quarter of last year. In the year-to-date period, 2002 costs also include amounts incurred in the first quarter of 2002 resulting from 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. Charges for depreciation and amortization decreased by $24.6 million in the second quarter and $52.9 million in the first six months of 2002, compared to the same periods last year. These decreases primarily resulted from 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 second quarter and first half of 2001 totaled $9.6 million and $19.1 million, respectively. General taxes increased by $2.4 million in the second quarter and $3.3 million in the first six months of 2002. Higher property taxes were partially offset by reductions due to state tax changes in connection with the Ohio electric industry restructuring. Other Income A reduction in discounts associated with the factoring of accounts receivable resulted in an increase in other income in the second quarter and first six months of 2002, compared to the prior year - increasing other income by $2.2 million and $3.0 million respectively. Preferred Stock Dividend Requirements Preferred stock dividend requirements decreased $3.5 million in the second quarter and $1.8 million in the first half of 2002, compared to the same periods last year, principally due to the completion of $100.0 million in refinancings. Premiums related to the optional first quarter redemptions partially offset the lower dividend requirements. Capital Resources and Liquidity ------------------------------- CEI has continuing cash requirements for planned capital expenditures and maturing debt. During the last two quarters of 2002, capital requirements for property additions and capital leases are expected to be about $110 million, including $9 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 and maturing long-term debt of $246.8 million and optional preferred stock redemptions of $45.0 million during the remainder of 2002. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. As of June 30, 2002, CEI had about $0.7 million of cash and temporary investments and $124.4 million of short-term indebtedness to associated companies. Under its first mortgage indenture, excluding property additions associated with the pending sale of coal-fired generating plants, CEI had the capability to issue up to $314 million of additional first mortgage bonds on the basis of property additions and retired bonds as of June 30, 2002. CEI has no restrictions on the issuance of preferred stock. 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. On May 23, 2002, FirstEnergy purchased an unused reactor vessel head from Consumers Energy's Midland Nuclear Plant - similar in design to the Davis-Besse Plant. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant changes in senior and mid-level managers at the plant and in its corporate nuclear organization. It has also established an independent oversight panel consisting of industry experts to assist in Davis- 41 Besse restart efforts and to provide advice regarding the safe return of Davis-Besse to service. FirstEnergy expects to complete refurbishment and installation of the replacement reactor head as well as any other work related to restart of the plant in the fourth quarter of this year. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. The estimated, incremental costs (capital and expense) associated with the extended Davis-Besse outage (CEI's share - 51.38%) in 2002 are: Incremental Costs of Davis-Besse Extended Outage (100%) ------------------------------------------------------- Expenditure Range ----------------- (In millions) Replace reactor vessel head (principally capital expenditures). $55 - $75 Primarily operating expenses (pre-tax): Additional maintenance (including acceleration of programs).... $50 - $70 Replacement power for July and August 2002..................... $40 Replacement power for September through December 2002.......... $40 - $60 On July 31, 2002, Fitch revised its rating outlook for CEI securities to negative from stable. The revised outlook reflects the adverse impact of the unplanned outage at the Davis-Besse Plant and Fitch's judgment at that time about NRG's financial ability to consummate the purchase of four power plants from FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. Environmental Matters --------------------- Various environmental liabilities have been recognized on the Consolidated Balance Sheet as of June 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 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. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. CEI has accrued liabilities of approximately $2.8 million as of June 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. FirstEnergy's most recent review was completed in June 2002. The results of that review indicate that no impairment of goodwill is appropriate. 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 - $908 million as of June 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. 42 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 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 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 will be recorded if the cost to settle the retirement obligation differs from the carrying amount. CEI has identified various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the second half of 2002. 43
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ---------------------- --------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) OPERATING REVENUES........................................ $250,307 $263,003 $494,474 $534,638 -------- -------- -------- -------- OPERATING EXPENSES AND TAXES: Fuel................................................... 9,427 12,015 20,818 24,768 Purchased power........................................ 79,352 86,713 161,756 175,065 Nuclear operating costs................................ 45,542 37,111 120,640 84,759 Other operating costs.................................. 35,920 37,287 70,799 75,913 -------- -------- -------- -------- Total operation and maintenance expenses........... 170,241 173,126 374,013 360,505 Provision for depreciation and amortization............ 19,748 29,240 41,116 62,015 General taxes.......................................... 13,449 13,879 27,197 29,940 Income taxes........................................... 12,710 13,403 8,331 20,489 -------- -------- -------- -------- Total operating expenses and taxes................. 216,148 229,648 450,657 472,949 -------- -------- -------- -------- OPERATING INCOME.......................................... 34,159 33,355 43,817 61,689 OTHER INCOME.............................................. 3,743 2,178 8,086 5,966 -------- -------- -------- -------- INCOME BEFORE NET INTEREST CHARGES........................ 37,902 35,533 51,903 67,655 -------- -------- -------- -------- NET INTEREST CHARGES: Interest on long-term debt............................. 15,601 16,616 31,473 33,860 Allowance for borrowed funds used during construction.. (382) (2,914) (810) (3,263) Other interest expense (credit)........................ (360) (1,133) (1,095) (2,111) -------- -------- -------- -------- Net interest charges............................... 14,859 12,569 29,568 28,486 -------- -------- -------- -------- NET INCOME................................................ 23,043 22,964 22,335 39,169 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,210 4,030 6,934 8,075 -------- -------- -------- -------- EARNINGS ON COMMON STOCK.................................. $ 20,833 $ 18,934 $ 15,401 $ 31,094 ======== ======== ======== ======== The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.
44
THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, 2002 2001 ----------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $1,588,298 $1,578,943 Less--Accumulated provision for depreciation.............................. 672,742 645,865 ---------- ---------- 915,556 933,078 ---------- ---------- Construction work in progress- Electric plant.......................................................... 61,370 40,220 Nuclear fuel............................................................ 26,383 19,854 ---------- ---------- 87,753 60,074 ---------- ---------- 1,003,309 993,152 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust................................................ 245,305 262,131 Nuclear plant decommissioning trusts...................................... 171,306 156,084 Long-term notes receivable from associated companies...................... 162,255 162,347 Other..................................................................... 3,684 4,248 ---------- ---------- 582,550 584,810 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 453 302 Receivables- Customers............................................................... 6,993 5,922 Associated companies.................................................... 48,210 64,667 Other................................................................... 23,835 9,709 Notes receivable from associated companies................................ 15,906 7,607 Materials and supplies, at average cost- Owned................................................................... 13,460 13,996 Under consignment....................................................... 19,406 17,050 Prepayments and other..................................................... 3,649 14,580 ---------- ---------- 131,912 133,833 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 400,902 388,846 Goodwill.................................................................. 445,732 445,732 Other..................................................................... 31,505 25,745 ---------- ---------- 878,139 860,323 ---------- ---------- $2,595,910 $2,572,118 ========== ==========
45
THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 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................................................... 328,559 328,559 Retained earnings....................................................... 123,237 113,436 ---------- ---------- Total common stockholder's equity................................... 647,466 637,665 Preferred stock not subject to mandatory redemption....................... 126,000 126,000 Long-term debt............................................................ 566,624 646,174 ---------- ---------- 1,340,090 1,409,839 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 328,730 347,593 Accounts payable- Associated companies.................................................... 67,896 53,960 Other................................................................... 7,133 27,418 Notes payable to associated companies..................................... 134,163 17,208 Accrued taxes............................................................. 49,229 39,848 Accrued interest.......................................................... 19,860 19,918 Other..................................................................... 27,730 40,222 ---------- ---------- 634,741 546,167 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 220,953 213,145 Accumulated deferred investment tax credits............................... 30,369 31,342 Nuclear plant decommissioning costs....................................... 177,648 162,426 Pensions and other postretirement benefits................................ 121,343 120,561 Other..................................................................... 70,766 88,638 ---------- ---------- 621,079 616,112 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $2,595,910 $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.
46
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ---------------------- ---------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 23,043 $ 22,964 $ 22,335 $ 39,169 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 19,748 29,240 41,116 62,015 Nuclear fuel and lease amortization................ 2,671 5,236 6,244 10,410 Deferred income taxes, net......................... 578 994 5,892 3,152 Investment tax credits, net........................ (487) (487) (973) (973) Receivables........................................ (18,762) (13,617) 1,260 4,000 Materials and supplies............................. (1,169) (711) (1,820) 10,712 Accounts payable................................... (9,210) (6,400) (6,349) (4,491) Accrued sale leaseback costs ...................... (53,332) (19,528) (28,454) (29,157) Other.............................................. 12,447 778 2,041 (19,397) -------- -------- -------- -------- Net cash provided from (used for) operating activities ..................................... (24,473) 18,469 41,292 75,440 -------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net........................... 47,957 7,491 116,955 -- Redemptions and Repayments- Preferred stock...................................... -- -- 85,299 -- Long-term debt....................................... 12,169 25,949 12,263 31,812 Short-term borrowings, net........................... -- -- -- 34,445 Dividend Payments- Common stock......................................... -- -- 5,600 14,700 Preferred stock...................................... 2,210 4,028 5,635 8,073 -------- -------- -------- -------- Net cash used for (provided from) financing activities ..................................... (33,578) 22,486 (8,158) 89,030 -------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... 14,702 8,481 40,261 20,509 Loans to associated companies.......................... 1,906 5,548 8,207 123,438 Loan payments from associated companies................ -- (21,556) -- (25,104) Capital trust investments.............................. (16,883) (520) (16,826) (17,705) Sale of assets to associated companies................. -- (5,548) -- (123,438) Other.................................................. 11,536 9,936 17,657 9,746 -------- -------- -------- -------- Net cash used for (provided from) investing activities ..................................... 11,261 (3,659) 49,299 (12,554) -------- -------- -------- -------- Net increase (decrease) in cash and cash equivalents...... (2,156) (358) 151 (1,036) Cash and cash equivalents at beginning of period.......... 2,609 707 302 1,385 -------- -------- -------- -------- Cash and cash equivalents at end of period................ $ 453 $ 349 $ 453 $ 349 ======== ======== ======== ======== The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.
47 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 June 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and six-month periods ended June 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 August 8, 2002 48 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 by $12.7 million or 4.8% in the second quarter and $40.2 million or 7.5% in the first half 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 and reduced sales to wholesale customers. Kilowatt-hour sales to generation customers decreased by 3.5% in the second quarter and 11.7% in the first six 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 15.3% in the second quarter of 2002 from 6.1% in the same period last year. Despite the reduction in generation load to alternative suppliers in the second quarter, kilowatt-hour sales to generation customers decreased only 3.5%, demonstrating some strength in the Toledo Edison service area. Automotive and automotive-related industrial customers continue to provide sales support in Toledo's franchise area. During the first six months of 2002, TE's share of electric generation sales in its franchise areas decreased by 11.5 percentage points, compared to the same period in 2001. Distribution deliveries increased by 7.0% in the second quarter of 2002 from the same quarter last year, increasing revenues from electricity throughput by $8.6 million due to higher sales in all customer sectors - residential, commercial and industrial. In addition to the benefit derived by TE's franchise area economy from automotive and automotive-related manufacturers, warmer weather in June 2002 increased air-conditioning load, as compared to the second quarter last year. In the first half of 2002, distribution deliveries increased slightly; however, revenues were lower reflecting a net decrease in average unit prices. 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 second quarter and first six months of 2002, compared to the corresponding periods of 2001 - reducing comparable revenues by $3.6 million and $7.7 million, respectively. These revenue reductions are deferred for future recovery under TE's transition plan and do not materially affect current period earnings. Sales to wholesale customers were also lower in both the second quarter and year-to-date periods of 2002, compared to the same periods last year, primarily reflecting reduced revenues from FES. The sources of changes in operating revenues during the second quarter and first six 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 June 30, 2002 ---------------------------- 3 Months 6 Months -------- -------- (In millions) Retail: Generation sales...................... $ (2.8) $(15.0) Distribution deliveries............... 8.6 (7.2) Increased shopping incentives......... (3.6) (7.7) ------ ------ Total Retail.......................... 2.2 (29.9) Wholesale............................... (15.0) (9.5) Other................................... 0.1 (0.8) ------ ------ Net Decrease in Operating Revenue....... $(12.7) $(40.2) ====== ====== 49 Operating Expenses and Taxes Total operating expenses and taxes declined by $13.5 million in the second quarter and $22.3 million in the first six months of 2002 from the corresponding period of 2001. Purchased power costs decreased $7.4 million and $13.3 million in the second quarter and first six months of 2002, compared to the same periods last year, primarily due to lower unit costs in the second quarter and reduced volume requirements supporting lower generation kilowatt-hour sales in the year-to-date period. Nuclear operating costs increased by $8.4 million in the second quarter and $35.9 million in the first half of 2002 from the same periods in 2001. Costs related to the extended outage at the Davis-Besse nuclear plant (see Capital Resources and Liquidity) and to a lesser extent additional operating costs at Beaver Valley Unit 2 and the Perry Plant, accounted for the increase in nuclear costs in the second quarter compared to the second quarter of last year. During the first six months of 2002, costs also included amounts incurred in the first quarter of 2002 from 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. Charges for depreciation and amortization decreased by $9.5 million in the second quarter and $20.9 million in the first six months of 2002, compared to the same periods last year. These decreases primarily resulted from 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 second quarter and first half of 2001 totaled $3.1 million and $6.2 million, respectively. General taxes decreased by $2.7 million in the first six months of 2002, compared to the same period last year, due to state tax changes in connection with the Ohio electric industry restructuring. Net Interest Charges Net interest charges increased by $2.3 million in the second quarter of 2002, compared to the same quarter last year, reflecting in part TE's higher short-term borrowing levels from affiliates. Capital Resources and Liquidity ------------------------------- TE has continuing cash requirements for planned capital expenditures and maturing debt. During the last half of 2002, capital requirements for property additions are expected to be about $72 million, including $5 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 preferred stock and maturing long-term debt of $152.4 million and optional debt redemptions of $15.0 million during the remainder of 2002. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. As of June 30, 2002, TE had about $16.4 million of cash and temporary investments and $134.2 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 had the capability to issue up to $131 million of additional first mortgage bonds on the basis of property additions and retired bonds as of June 30, 2002. Under the earnings coverage test contained in TE's charter, no preferred stock could be issued based on earnings through the second quarter of 2002. 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. On May 23, 2002, FirstEnergy purchased an unused reactor vessel head from Consumers Energy's Midland Nuclear Plant - similar in design to the Davis-Besse Plant. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant changes in senior and mid-level managers at the plant and in its corporate nuclear organization. It has also established an independent oversight panel consisting of industry experts to assist in Davis-Besse restart efforts and to provide advice regarding the safe return of Davis-Besse to service. FirstEnergy expects to complete refurbishment and installation of the replacement reactor head as well as any other work related to restart of the plant in the fourth quarter of this year. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. 50 The estimated, incremental costs (capital and expense) associated with the extended Davis-Besse outage (TE share - 48.62%) in 2002 are: Incremental Costs of Davis-Besse Extended Outage (100%) ------------------------------------------------------- Expenditure Range ----------------- (In millions) Replace reactor vessel head (principally capital expenditures). $55 - $75 Primarily operating expenses (pre-tax): Additional maintenance (including acceleration of programs).... $50 - $70 Replacement power for July and August 2002..................... $40 Replacement power for September through December 2002.......... $40 - $60 On July 31, 2002, Fitch revised its rating outlook for TE securities to negative from stable. The revised outlook reflects the adverse impact of the unplanned outage at the Davis-Besse Plant and Fitch's judgment at that time about NRG's financial ability to consummate the purchase of four power plants from FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. State Regulatory Matters ------------------------ The transition cost portion of TE's 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, TE assumed the risk of not recovering up to $80 million of transition revenue if the rate of customers (excluding contracts and full-service accounts) switching their service from TE does not reach 20% for any consecutive twelve-month period by December 31, 2005 - the end of the market development period. As of June 30, 2002, the annualized customer-switching rate essentially eliminated TE's risk of not recovering transition costs, since over 113,000 of its customers have requested generation services from other authorized suppliers. Environmental Matters --------------------- Various environmental liabilities have been recognized on the Consolidated Balance Sheet as of June 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 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. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. TE has accrued liabilities of approximately $0.2 million as of June 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 ------------------------------- 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 most recent review was completed in June 2002. The results of that review indicate that no impairment of goodwill is appropriate. 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 - $401 million as of June 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. 51 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 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 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 will be recorded if the cost to settle the retirement obligation differs from the carrying amount. TE has identified various applicable legal obligations as defined under the new standard and expects to have completed an analysis of their financial impact in the second half of 2002. 52
PENNSYLVANIA POWER COMPANY STATEMENTS OF INCOME (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ---------------------- ---------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) OPERATING REVENUES........................................ $127,737 $124,701 $252,072 $253,098 -------- -------- -------- -------- OPERATING EXPENSES AND TAXES: Fuel................................................... 6,379 5,887 12,712 12,528 Purchased power........................................ 35,663 33,791 75,626 79,559 Nuclear operating costs................................ 19,473 19,252 41,805 39,517 Other operating costs.................................. 9,717 11,897 19,669 22,193 -------- -------- -------- -------- Total operation and maintenance expenses........... 71,232 70,827 149,812 153,797 Provision for depreciation and amortization............ 14,208 14,267 28,412 28,530 General taxes.......................................... 6,006 1,261 12,010 5,741 Income taxes........................................... 14,835 15,482 25,251 26,157 -------- -------- -------- -------- Total operating expenses and taxes................. 106,281 101,837 215,485 214,225 -------- -------- -------- -------- OPERATING INCOME.......................................... 21,456 22,864 36,587 38,873 OTHER INCOME.............................................. 476 747 1,141 1,622 -------- -------- -------- -------- INCOME BEFORE NET INTEREST CHARGES........................ 21,932 23,611 37,728 40,495 -------- -------- -------- -------- NET INTEREST CHARGES: Interest expense....................................... 4,268 4,674 8,366 9,402 Allowance for borrowed funds used during construction.. (345) (108) (597) (340) -------- -------- -------- -------- Net interest charges............................... 3,923 4,566 7,769 9,062 -------- -------- -------- -------- NET INCOME................................................ 18,009 19,045 29,959 31,433 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 926 926 1,852 1,852 -------- -------- -------- -------- EARNINGS ON COMMON STOCK.................................. $ 17,083 $ 18,119 $ 28,107 $ 29,581 ======== ======== ======== ======== The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.
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PENNSYLVANIA POWER COMPANY BALANCE SHEETS (Unaudited) June 30, December 31, 2002 2001 -------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $672,863 $664,432 Less--Accumulated provision for depreciation.............................. 301,051 290,216 -------- -------- 371,812 374,216 -------- -------- Construction work in progress- Electric plant.......................................................... 30,751 24,141 Nuclear fuel............................................................ 469 2,921 -------- -------- 31,220 27,062 -------- -------- 403,032 401,278 -------- -------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 121,309 116,634 Long-term notes receivable from associated companies...................... 39,109 39,290 Other..................................................................... 21,916 21,597 -------- -------- 182,334 177,521 -------- -------- CURRENT ASSETS: Cash and cash equivalents................................................. 590 67 Receivables- Customers (less accumulated provisions of $666,000 and $619,000, respectively, for uncollectible accounts)............................. 48,991 40,890 Associated companies.................................................... 32,813 36,491 Other................................................................... 4,384 4,787 Notes receivable from associated companies................................ 37,718 54,411 Materials and supplies, at average cost................................... 27,881 25,598 Prepayments............................................................... 14,465 5,682 -------- -------- 166,842 167,926 -------- -------- DEFERRED CHARGES: Regulatory assets......................................................... 182,570 208,838 Other..................................................................... 4,596 4,534 -------- -------- 187,166 213,372 -------- -------- $939,374 $960,097 ======== ========
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PENNSYLVANIA POWER COMPANY BALANCE SHEETS (Unaudited) June 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....................................................... 55,706 35,398 -------- -------- Total common stockholder's equity................................... 244,096 223,788 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................................................................... 240,480 240,983 -------- -------- 537,931 539,190 -------- -------- CURRENT LIABILITIES: Currently payable long-term debt- Associated companies.................................................... -- 18,090 Other................................................................... 12,077 12,075 Accounts payable- Associated companies.................................................... 29,798 50,604 Other................................................................... 3,341 1,441 Accrued taxes............................................................. 41,942 18,853 Accrued interest.......................................................... 5,333 5,264 Other..................................................................... 9,063 9,675 -------- -------- 101,554 116,002 -------- -------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 126,803 136,808 Accumulated deferred investment tax credits............................... 3,959 4,108 Nuclear plant decommissioning costs....................................... 121,771 117,096 Other..................................................................... 47,356 46,893 -------- -------- 299,889 304,905 -------- -------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... -------- -------- $939,374 $960,097 ======== ======== The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets.
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PENNSYLVANIA POWER COMPANY STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Six Months Ended June 30, June 30, --------------------- ---------------------- 2002 2001 2002 2001 ------- -------- -------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $18,009 $ 19,045 $ 29,959 $ 31,433 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 14,208 14,267 28,412 28,530 Nuclear fuel and lease amortization................ 4,852 4,359 9,568 9,241 Deferred income taxes, net......................... (1,950) (3,555) (3,875) (6,036) Investment tax credits, net........................ (655) (699) (1,320) (1,410) Receivables........................................ (3,338) (7,751) (4,020) 1,314 Materials and supplies............................. (1,711) (1,656) (2,283) 6,308 Accounts payable................................... (3,147) 7,347 (18,906) (26,007) Accrued taxes ..................................... 12,439 (3,505) 23,089 3,369 Other.............................................. 7,220 7,128 (8,162) (8,616) ------- -------- -------- -------- Net cash provided from operating activities...... 45,927 34,980 52,462 38,126 ------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... -- 32,603 -- 32,603 Redemptions and Repayments- Long-term debt....................................... 623 4,804 41,290 9,722 Dividend Payments- Common stock......................................... -- -- 7,800 6,300 Preferred stock...................................... 926 926 1,852 1,852 ------- -------- -------- -------- Net cash used for (provided from) financing activities ..................................... 1,549 (26,873) 50,942 (14,729) ------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... 8,343 8,552 16,426 13,910 Loans to associated companies.......................... 36,357 30,828 -- 30,828 Loan payment from parent............................... -- -- (16,706) (13,640) Sale of assets to associated companies................. -- (6,053) -- (6,053) Other.................................................. 89 (3,175) 1,277 (2,860) ------- -------- -------- -------- Net cash used for investing activities........... 44,789 30,152 997 22,185 ------- -------- -------- -------- Net increase (decrease) in cash and cash equivalents...... (411) 31,701 523 30,670 Cash and cash equivalents at beginning of period.......... 1,001 2,444 67 3,475 ------- -------- -------- -------- Cash and cash equivalents at end of period................ $ 590 $ 34,145 $ 590 $ 34,145 ======= ======== ======== ======== The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.
56 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 June 30, 2002, and the related statements of income and cash flows for each of the three-month and six-month periods ended June 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 August 8, 2002 57 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 by $3.0 million or 2.4% in the second quarter and decreased by $1.0 million or 0.4% in the first half of 2002, as compared to the same periods of 2001. Higher operating revenues in the second quarter of 2002 primarily resulted from the return of generation customers previously served by alternative suppliers, while lower year-to-date operating revenues principally resulted from reduced sales revenues to wholesale customers. Sales of electric generation by alternative suppliers as a percent of total sales delivered in Penn's franchise area decreased to 0.4% in the second quarter of 2002 from 5.0% in the same period last year. During the first six months of 2002, Penn's share of electric generation sales in its franchise area increased by 6.9 percentage points, compared to the same period in 2001. Distribution revenues changed very little in the second quarter and first six months of 2002, compared to the same periods last year. Higher residential sales, which benefited from warmer weather in June 2002, increased in both periods but were more than offset in the first six months of 2002 by reduced deliveries to commercial and industrial customers, as a result of the decline in economic conditions. Lower wholesale revenues partially offset higher generation and distribution revenues in the second quarter of 2002 moderating the increase in operating revenues in that period and resulted in a decrease in revenues during the first six months of 2002, compared to the prior year. Reduced sales revenues from FES accounted for nearly all of the decrease in wholesale revenues in both periods. The sources of changes in operating revenues during the second quarter and first six 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 June 30, 2002 ---------------------------- 3 Months 6 Months -------- -------- (In millions) Retail: Generation sales............................. $ 6.4 $ 9.9 Distribution deliveries...................... 0.9 (0.2) ----- ------ Total Retail................................. 7.3 9.7 Wholesale...................................... (3.6) (11.7) Other.......................................... (0.7) 1.0 ----- ------ Net Increase (Decrease) in Operating Revenues.. $ 3.0 $ (1.0) ===== ====== Operating Expenses and Taxes Total operating expenses and taxes increased by $4.4 million in the second quarter and $1.3 million in the first six months of 2002 from the corresponding period of 2001. Purchased power costs increased $1.9 million in the second quarter of 2002 from the same quarter last year as a result of higher volume requirements for customers returning from alternative suppliers. This increase was partially offset by reduced unit costs. During the first six months, purchased power costs decreased $3.9 million with lower unit costs more than offsetting the additional volume purchased to supply generation kilowatt-hour sales. In the first six months of 2002, nuclear operating costs increased by $2.3 million from the same period last year, primarily due to a larger ownership share of capacity in the refueling outage for Beaver Valley Unit 2 (13.74% owned) in the first quarter of 2002, compared to the Perry Plant (5.24% owned) in the first quarter of 2001. 58 General taxes increased by $4.7 million in the second quarter and $6.3 million in the first half of 2002 due in part to the successful resolution of certain property tax issues in the second quarter of 2001, which provided a one-time benefit of $3.0 million in that year. An increase in the gross receipts tax rate for 2002 also contributed to the increase in general taxes for both periods. Capital Resources and Liquidity ------------------------------- Penn has continuing cash requirements for planned capital expenditures and maturing debt. During the last two quarters of 2002, capital requirements for property additions and capital leases are expected to be about $27 million, including $5 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 June 30, 2002, Penn had about $38.3 million of cash and temporary investments and no short-term indebtedness. Under its first mortgage indenture, as of June 30, 2002, Penn had the capability to issue up to $290 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, $188 million of preferred stock (assuming no additional debt was issued) could be issued based on earnings through the second quarter of 2002. 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 - $183 million as of June 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. 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 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 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 will be recorded if the cost to settle the retirement obligation differs from the carrying amount. Penn has identified various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the second half of 2002. 59
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ----------------------- --------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) OPERATING REVENUES........................................ $501,232 | $521,054 $951,945 | $982,736 -------- | -------- -------- | -------- | | | | OPERATING EXPENSES AND TAXES: | | Fuel................................................... 1,298 | 1,440 2,474 | 2,778 Purchased power........................................ 249,466 | 275,627 460,451 | 491,293 Other operating costs.................................. 74,100 | 67,812 142,617 | 131,456 -------- | -------- -------- | -------- Total operation and maintenance expenses........... 324,864 | 344,879 605,542 | 625,527 Provision for depreciation and amortization............ 55,371 | 62,684 119,274 | 124,433 General taxes.......................................... 4,294 | 15,081 21,297 | 30,654 Income taxes........................................... 38,543 | 29,103 66,404 | 59,331 -------- | -------- -------- | -------- Total operating expenses and taxes................. 423,072 | 451,747 812,517 | 839,945 -------- | -------- -------- | -------- | | OPERATING INCOME.......................................... 78,160 | 69,307 139,428 | 142,791 | | OTHER INCOME.............................................. 2,196 | 2,401 5,022 | 3,559 -------- | -------- -------- | -------- | | INCOME BEFORE NET INTEREST CHARGES........................ 80,356 | 71,708 144,450 | 146,350 -------- | -------- -------- | -------- | | NET INTEREST CHARGES: | | Interest on long-term debt............................. 22,768 | 22,821 45,485 | 44,030 Allowance for borrowed funds used during construction.. (97) | 3 (579) | (431) Deferred interest...................................... (1,834) | (3,330) (1,385) | (6,406) Other interest expense (credit)........................ (533) | 3,485 (1,777) | 6,371 Subsidiaries' preferred stock dividend requirements.... 2,672 | 2,675 5,347 | 5,350 -------- | -------- -------- | -------- Net interest charges............................... 22,976 | 25,654 47,091 | 48,914 -------- | -------- -------- | -------- | | NET INCOME................................................ 57,380 | 46,054 97,359 | 97,436 | | PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 431 | 1,391 1,184 | 2,782 -------- | -------- -------- | -------- | | EARNINGS ON COMMON STOCK.................................. $ 56,949 | $ 44,663 $ 96,175 | $ 94,654 ======== | ======== ======== | ======== 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) June 30, December 31, 2002 2001 ---------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $3,496,702 $3,431,823 Less--Accumulated provision for depreciation.............................. 1,369,453 1,313,259 ---------- ---------- 2,127,249 2,118,564 Construction work in progress - electric plant............................ 37,643 60,482 ---------- ---------- 2,164,892 2,179,046 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 112,768 114,899 Nuclear fuel disposal trust............................................... 141,271 137,098 Long-term notes receivable from associated companies...................... 20,333 20,333 Other..................................................................... 11,908 6,643 ---------- ---------- 286,280 278,973 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 247,296 31,424 Receivables- Customers (less accumulated provisions of $10,353,000 and $12,923,000, respectively, for uncollectible accounts).............................. 221,683 226,392 Associated companies.................................................... 692 6,412 Other .................................................................. 21,221 20,729 Materials and supplies, at average cost................................... 1,303 1,348 Prepayments and other..................................................... 88,820 16,569 ---------- ---------- 581,015 302,874 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 3,180,896 3,324,804 Goodwill.................................................................. 1,926,526 1,926,526 Other..................................................................... 27,944 27,775 ---------- ---------- 5,135,366 5,279,105 ---------- ---------- $8,167,553 $8,039,998 ========== ==========
61
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 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................................................... 2,981,117 2,981,117 Accumulated other comprehensive loss.................................... (640) (472) Retained earnings....................................................... 59,518 29,343 ---------- ---------- Total common stockholder's equity................................... 3,193,708 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............. 125,247 125,250 Long-term debt............................................................ 1,223,520 1,224,001 ---------- ---------- 4,555,124 4,570,469 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 365,361 60,848 Accounts payable- Associated companies.................................................... 179,264 171,168 Other................................................................... 114,587 89,739 Notes payable to associated companies..................................... -- 18,149 Accrued taxes............................................................. 7,323 35,783 Accrued interest.......................................................... 24,026 25,536 Other..................................................................... 136,305 79,589 ---------- ---------- 826,866 480,812 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 579,425 514,216 Accumulated deferred investment tax credits............................... 11,691 13,490 Power purchase contract loss liability.................................... 1,757,948 1,968,823 Nuclear fuel disposal costs............................................... 164,834 163,377 Nuclear plant decommissioning costs....................................... 137,308 137,424 Other..................................................................... 134,357 191,387 ---------- ---------- 2,785,563 2,988,717 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $8,167,553 $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 Six Months Ended June 30, June 30, ----------------------- ------------------------ 2002 2001 2002 2001 --------- -------- --------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: | | Net income................................................ $ 57,380 | $ 46,054 $ 97,359 | $ 97,436 Adjustments to reconcile net income to net | | cash from operating activities- | | Provision for depreciation and amortization........ 55,371 | 62,684 119,274 | 124,433 Other amortization................................. 940 | 9,538 1,451 | 18,590 Deferred costs, net................................ (43,340) | (63,137) (108,948) | (113,874) Deferred income taxes, net......................... 27,862 | 3,507 36,540 | 19,918 Investment tax credits, net........................ (900) | (900) (1,799) | (1,799) Receivables........................................ (34,185) | (37,735) 9,937 | (105,386) Materials and supplies............................. 39 | (815) 45 | (843) Accounts payable................................... 37,910 | 47,133 32,944 | (30,031) Prepayments ....................................... (76,906) | (64,927) (70,650) | 26,465 Accrued taxes ..................................... (63,030) | (1,910) (28,460) | 33,301 Other.............................................. (4,347) | 84 1,491 | (17,250) --------- | -------- --------- | --------- Net cash provided from (used for) operating | | activities ..................................... (43,206) | (424) 89,184 | 50,960 --------- | -------- --------- | --------- | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | New Financing- | | Long-term debt....................................... 318,106 | 148,796 318,106 | 148,796 Short-term borrowings, net........................... -- | 13,700 -- | 76,800 Redemptions and Repayments- | | Preferred stock...................................... 5,000 | 2,500 5,000 | 2,500 Long-term debt....................................... -- | -- 50,000 | -- Short-term borrowings, net........................... -- | -- 18,149 | -- Dividend Payments- | | Common stock......................................... 66,000 | -- 66,000 | 75,000 Preferred stock...................................... 991 | 1,391 1,744 | 2,782 --------- | -------- --------- | --------- Net cash provided from financing activities...... 246,115 | 158,605 177,213 | 145,314 --------- | -------- --------- | --------- | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | Property additions..................................... 20,932 | 44,972 46,834 | 78,085 Decommissioning trust investments...................... 608 | 304 709 | 598 Other.................................................. 1,690 | 1,646 2,982 | 3,321 --------- | -------- --------- | --------- Net cash used for investing activities........... 23,230 | 46,922 50,525 | 82,004 --------- | -------- --------- | --------- | | | | Net increase in cash and cash equivalents................. 179,679 | 111,259 215,872 | 114,270 Cash and cash equivalents at beginning of period.......... 67,617 | 5,032 31,424 | 2,021 --------- | -------- --------- | --------- Cash and cash equivalents at end of period................ $ 247,296 | $116,291 $ 247,296 | $ 116,291 ========= | ======== ========= | ========= The preceding Notes to Financial Statements as they relate to Jersey Power & Light Company are an integral part of these statements.
63 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 June 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and six-month periods ended June 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 August 8, 2002 64 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 decreased by $19.8 million or 3.8% in the second quarter of 2002, and by $30.8 million or 3.1% in the first half 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. Three Months Ended Six Months Ended Sources of Operating Revenue Changes June 30, 2002 June 30, 2002 -------------------------------------------------------------------------------- Increase (Decrease) (In millions) Change in kilowatt-hour sales due to level of retail customers shopping for generation service ................ $ 16.1 $ 43.1 Change in other retail kilowatt-hour sales ................................. (2.7) (38.3) Change in wholesale sales ............... (38.9) (38.9) All other changes ....................... 5.7 3.3 ------- ------ Net Decrease in Operating Revenues ...... $(19.8) $(30.8) ====== ====== Electric Sales In the first half of 2002, a significant 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 six months of 2001, 8.7% of kilowatt-hours delivered were to shopping customers, whereas only 0.5% of kilowatt-hours delivered during the first six months of 2002 were to shopping customers. More than offsetting this increase in revenues from returning shopping customers were lower sales to wholesale customers during the first half of 2002. A decline in economic conditions resulted in a decrease in sales to industrial customers during the six months ended June 30, 2002; however, conditions began to improve in the second 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 six months ended June 30, 2002, as compared to the same periods in 2001, are summarized in the following table: Changes in Distribution Deliveries Three Months Ended Six Months Ended and Wholesale Generation Sales June 30, 2002 June 30, 2002 -------------------------------------------------------------------------------- Increase (Decrease) Residential............................ 1.1% (1.8)% Commercial............................. -- % 0.5 % Industrial............................. 0.8% (3.0)% ----- ----- Total Retail........................... 0.5% (1.1)% Wholesale.............................. (72.0)% (71.1)% ----- ----- Total ................................. (8.7)% (6.4)% ===== ===== Operating Expenses and Taxes Total operating expenses and taxes decreased by $28.7 million in the second quarter of 2002, and $27.4 million in the first six months of 2002, compared to the same periods in 2001. Purchased power costs decreased by $26.2 million and $30.8 million for the three and six month periods ended June 30, 2002, respectively, compared to the same periods in 2001, as a result of less power required and lower unit costs. Higher other operating costs of $6.3 million and $11.2 million in the three and six month periods ended June 30, 2002, respectively, were partially attributable to increases in pension and other employee benefit costs. Decreases in depreciation and amortization expenses of $7.3 million and $5.2 million for the 65 three and six month periods ended June 30, 2002, respectively, were due primarily to the cessation of amortization of regulatory assets related to the net investment in the previously divested Oyster Creek Nuclear Generating Station, which transferred to JCP&L Transition Funding LLC as bondable transition property during the second quarter of 2002 (see New Jersey Regulatory Matters for further discussion). These decreases were offset by higher depreciation due to higher average depreciable plant balances in the quarter and six months ended June 30, 2002 versus the same periods in 2001. General taxes decreased by $10.8 million in the second quarter and $9.4 million in the first six months of 2002, compared to the same periods in 2001 due principally to a reduction in the transitional energy facilities assessment. Net Interest Charges Net interest charges decreased by $2.7 million in the second quarter and $1.8 million in the first six months of 2002, compared to the same periods in 2001, primarily due to reduced short-term borrowing levels and 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 and $50 million of notes in March 2002. These transactions had an offsetting effect on net interest charges for the quarter ended June 30, 2002, and resulted in a $1.5 million increase in net interest charges for the six months ended June 30, 2002. Capital Resources and Liquidity ------------------------------- JCP&L has continuing cash requirements for planned capital expenditures and preferred stock sinking fund requirements, which are expected to be satisfied from internal cash and/or short-term credit arrangements. During the remaining six months of 2002, capital requirements for property additions are expected to be about $70.0 million. As of June 30, 2002, JCP&L had mandatory sinking fund requirements for preferred stock of $8.3 million, which JCP&L satisfied in July 2002, in addition to $8.3 million of preferred stock it redeemed pursuant to an optional sinking fund provision. In July and August 2002, JCP&L also used proceeds from the sale of transition bonds (see New Jersey Regulatory Matters) to redeem $142.0 million of long-term debt and $29.8 million of preferred stock. As of June 30, 2002, JCP&L had about $247.3 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 June 30, 2002, JCP&L had the capability to issue up to $291 million of additional FMBs on the basis of retired bonds. Based upon applicable earnings coverage tests and its charter, JCP&L could issue $126.6 million of preferred stock (assuming no additional debt was issued) based on earnings through June 30, 2002. 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 second 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 March 31, 2002.......... $14.6 Settled contracts................................... (3.2) Change in techniques/assumptions.................... -- Decrease in value of existing contracts............. (5.3) ----- Outstanding net asset as of June 30, 2002........... $ 6.1 ===== 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 66 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 .... $0.4 $ -- $ -- $-- $0.4 Prices based on models** .. -- -- -- 5.7 5.7 ---- ---- ---- ---- ---- Total ................... $0.4 $ -- $ -- $5.7 $6.1 ==== ==== ==== ==== ==== * For the last half 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 and volatilities 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 June 30, 2002. New Jersey Regulatory Matters ----------------------------- Under New Jersey transition legislation, all electric distribution companies in that state were required to file rate cases by August 1, 2002. On August 1, 2002, JCP&L submitted two rate filings with the New Jersey Board of Public Utilities (NJBPU). The first related to base electric rates (Delivery Charge Filing). The second was a request to recover deferred costs (Deferral Filing) primarily associated with mandated purchase-power contracts with non-utility generators (NUGs) - which produce power at prices that exceed wholesale market prices - and providing Basic Generation Service (BGS) to customers in excess of the state's generation rate cap. The new rate structure, when approved, becomes effective on August 1, 2003. Delivery Charge Filing - The delivery charge filing includes recovery of JCP&L's distribution, transmission, customer service, administrative and general costs, along with taxes and some assessment fees. JCP&L is requesting a decrease in the delivery charge of $11 million, or a 0.6% rate reduction. The filing uses calendar year 2002 as the test year and is based on a net rate base value of $2.1 billion and allowed return on common equity of 12%. The December 31, 2001 capital structure used in the filing has been modified to eliminate purchase accounting adjustments from the merger of FirstEnergy and GPU, Inc. and to remove a pre-merger $300 million deferred balance write-off required by the NJBPU merger approval order (See Deferral Filing). The modified capital structure is comparable to JCP&L's pre-merger capital structure. Deferral Filing - The deferral filing addresses the current Market Transition Charge (MTC) and Societal Benefits Charge (SBC), which were confirmed by a 2001 rate order. The combined effect of JCP&L's MTC and SBC requests would result in a 2.8% rate increase with securitization of a deferred balance; if securitization is not available, there would be an additional 6.5% increase with a four-year amortization of the deferred balance. JCP&L was authorized to defer energy-related costs incurred in providing BGS to non-shopping retail customers and costs incurred under NUG agreements and purchased power agreements that exceeded the amounts collected under the current BGS and MTC rates. Additionally, in 2001, JCP&L wrote off $300 million of deferred costs upon receipt of the NJBPU merger approval order, in order to ensure that customers receive the benefit of future merger savings. This amount is not included in the requested deferred cost recovery. JCP&L's filing proposes to recover the MTC deferred balance through a securitization transaction involving the issuance of transition bonds in a principal amount equal to the projected July 31, 2003 MTC deferred balance of $684 million. The transition bond-related rate increase would be approximately $69 million per year, or a 3.5% increase. An alternative to securitization of the deferred balance would be to recover the deferred balance over a four-year amortization period with interest. This alternative approach would require an MTC rate increase of $195 million or an increase of 10%. JCP&L's securitization proposal minimizes the required customer rate increase. Stranded cost securitization would create a transition bond charge (TBC) which would be the revenue collection mechanism for the transition bond principal and interest payments. In June 2002, JCP&L sold $320 million principal amount of transition bonds to securitize its net investment in the Oyster Creek Nuclear Generating Facility. The TBC was offset by a 67 corresponding reduction in the MTC since the stranded Oyster Creek investment was initially being amortized through the MTC. Securitization of the deferred energy-related cost balance would require an increase in the TBC. The 2001 rate order confirmed the establishment of the SBC to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation. JCP&L's request would reduce the SBC by $14 million, or a 0.7% rate decrease. Environmental Matters --------------------- Various environmental liabilities have been recognized on the Consolidated Balance Sheet as of June 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. 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. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. 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 SBC. JCP&L has accrued liabilities aggregating approximately $50.0 million as of June 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 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. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. JCP&L's more significant accounting policies are described below. 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 the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill, which will be reviewed for impairment at least annually. FirstEnergy's most recent review was completed in June 2002. The results of that review indicate that no impairment of JCP&L's $1.9 billion of goodwill is appropriate. Regulatory Accounting JCP&L is subject to regulation that sets the prices (rates) it is permitted to charge customers based on costs that 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 June 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 must be 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 68 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 Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- In June 2001, the Financial Accounting Standards Board issued SFAS 143, "Accounting for Asset Retirement Obligations." The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets with adoption required as of 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 will be recorded if the cost to settle the retirement obligation differs from the carrying amount. JCP&L has identified various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the second half of 2002. 69
METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ---------------------- --------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) OPERATING REVENUES........................................ $240,003 | $222,536 $485,793 | $443,556 -------- | -------- -------- | -------- | | OPERATING EXPENSES AND TAXES: | | Purchased power........................................ 139,961 | 128,375 288,910 | 253,602 Other operating costs.................................. 33,570 | 30,287 62,575 | 66,840 -------- | -------- -------- | -------- Total operation and maintenance expenses........... 173,531 | 158,662 351,485 | 320,442 Provision for depreciation and amortization............ 15,046 | 21,435 30,338 | 39,229 General taxes.......................................... 14,815 | 10,601 31,727 | 21,233 Income taxes........................................... 9,656 | 7,161 19,212 | 13,574 -------- | -------- -------- | -------- Total operating expenses and taxes................. 213,048 | 197,859 432,762 | 394,478 -------- | -------- -------- | -------- | | OPERATING INCOME.......................................... 26,955 | 24,677 53,031 | 49,078 | | OTHER INCOME.............................................. 5,456 | 5,317 10,587 | 10,002 -------- | -------- -------- | -------- | | INCOME BEFORE NET INTEREST CHARGES........................ 32,411 | 29,994 63,618 | 59,080 -------- | -------- -------- | -------- | | NET INTEREST CHARGES: | | Interest on long-term debt............................. 10,227 | 9,155 20,682 | 18,309 Allowance for borrowed funds used during construction.. (280) | (27) (564) | (186) Deferred interest...................................... (42) | -- (235) | -- Other interest expense................................. 898 | 3,137 1,171 | 5,373 Subsidiaries' preferred stock dividend requirements.... 1,941 | 1,837 3,779 | 3,675 -------- | -------- -------- | -------- Net interest charges............................... 12,744 | 14,102 24,833 | 27,171 -------- | -------- -------- | -------- | | | | NET INCOME................................................ $ 19,667 | $ 15,892 $ 38,785 | $ 31,909 ======== | ======== ======== | ======== The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.
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METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, 2002 2001 ----------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $1,630,079 $1,609,974 Less--Accumulated provision for depreciation.............................. 552,723 530,006 ---------- ---------- 1,077,356 1,079,968 Construction work in progress.............................................. 12,654 14,291 ---------- ---------- 1,090,010 1,094,259 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 162,208 157,699 Long-term notes receivable from associated companies...................... 12,418 12,418 Other..................................................................... 23,131 13,391 ---------- ---------- 197,757 183,508 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 5,335 25,274 Receivables- Customers (less accumulated provisions of $10,477,000 and $12,271,000, respectively, for uncollectible accounts)............................. 114,217 112,257 Associated companies.................................................... 17,515 8,718 Other................................................................... 19,726 16,675 Prepayments and other..................................................... 23,665 12,239 ---------- ---------- 180,458 175,163 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 1,290,057 1,320,412 Goodwill.................................................................. 784,443 784,443 Other..................................................................... 48,877 49,402 ---------- ---------- 2,123,377 2,154,257 ---------- ---------- $3,591,602 $3,607,187 ========== ==========
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METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 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............................................ $1,274,325 $1,274,325 Accumulated other comprehensive income (loss)........................... (91) 11 Retained earnings....................................................... 23,402 14,617 ---------- ---------- Total common stockholder's equity................................... 1,297,636 1,288,953 Company-obligated trust preferred securities.............................. 92,304 92,200 Long-term debt............................................................ 570,968 583,077 ---------- ---------- 1,960,908 1,964,230 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 60,029 30,029 Accounts payable- Associated companies.................................................... 60,403 67,351 Other................................................................... 40,773 36,750 Notes payable to associated companies..................................... 71,152 72,011 Accrued taxes............................................................. 1,949 7,037 Accrued interest.......................................................... 17,904 17,468 Other..................................................................... 11,267 13,652 ---------- ---------- 263,477 244,298 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 315,630 300,438 Accumulated deferred investment tax credits............................... 12,886 13,310 Purchase power contract loss liability.................................... 686,517 730,662 Nuclear fuel disposal costs............................................... 37,235 36,906 Nuclear plant decommissioning costs....................................... 270,499 268,967 Other..................................................................... 44,450 48,376 ---------- ---------- 1,367,217 1,398,659 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $3,591,602 $3,607,187 ========== ========== The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets.
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METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ---------------------- ---------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: | | Net income................................................ $ 19,667 | $ 15,892 $ 38,785 | $ 31,909 Adjustments to reconcile net income to net | | cash from operating activities- | | Provision for depreciation and amortization........ 15,046 | 21,435 30,338 | 39,229 Other amortization................................. (456) | 519 (1,394) | 756 Deferred costs, net................................ (8,826) | (24,690) (2,937) | (24,394) Deferred income taxes, net......................... 6,937 | 9,505 9,504 | 10,877 Investment tax credits, net........................ (212) | (212) (424) | (424) Receivables........................................ (26,722) | (13,973) (13,808) | (14,146) Accounts payable................................... 17,887 | 60,029 (2,925) | 57,746 Other.............................................. 14,375 | 7,070 (36,956) | (33,403) -------- | -------- -------- | -------- Net cash provided from operating activities...... 37,696 | 75,575 20,183 | 68,150 -------- | -------- -------- | -------- | | CASH FLOWS FROM FINANCING ACTIVITIES: | | New Financing- | | Long-term debt....................................... 49,750 | -- 49,750 | -- Short-term borrowings, net........................... -- | 11,100 -- | 51,400 Redemptions and Repayments- | | Long-term debt....................................... -- | -- 30,000 | -- Short-term borrowings, net........................... 56,406 | -- 859 | -- Dividend Payments- | | Common stock......................................... 30,000 | -- 30,000 | 15,000 -------- | -------- -------- | -------- Net cash used for (provided from) financing | | activities ..................................... 36,656 | (11,100) 11,109 | (36,400) -------- | -------- -------- | -------- | | CASH FLOWS FROM INVESTING ACTIVITIES: | | Property additions..................................... 11,691 | 13,229 20,787 | 25,022 Decommissioning trust investments...................... 4,826 | 2,371 7,987 | 4,742 Other.................................................. -- | 1,564 239 | 4,555 -------- | -------- -------- | -------- Net cash used for investing activities........... 16,517 | 17,164 29,013 | 34,319 -------- | -------- -------- | -------- | | Net increase (decrease) in cash and cash equivalents...... (15,477) | 69,511 (19,939) | 70,231 Cash and cash equivalents at beginning of period.......... 20,812 | 4,159 25,274 | 3,439 -------- | -------- -------- | -------- Cash and cash equivalents at end of period................ $ 5,335 | $ 73,670 $ 5,335 | $ 73,670 ======== | ======== ======== | ======== The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.
73 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 June 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and six-month periods ended June 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 August 8, 2002 74 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. Results of Operations --------------------- Operating revenues increased by $17.4 million or 7.9% in the second quarter of 2002, and by $42.2 million or 9.5% in the first six 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. Three Months Ended Six Months Ended Sources of Operating Revenue Changes June 30, 2002 June 30, 2002 -------------------------------------------------------------------------------- Increase (Decrease) (In millions) Change in kilowatt-hour sales due to level of retail customers shopping for generation service ..................... $21.3 $56.8 Change in other retail kilowatt-hour sales .................................. 5.5 (0.7) Change in wholesale sales.................. (8.7) (9.7) All other changes.......................... (0.7) (4.2) ----- ----- Net Increase in Operating Revenues......... $17.4 $42.2 ===== ===== Electric Sales In the first half of 2002, a significant 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 half of 2001, 26.7% of kilowatt-hours delivered were to shopping customers, whereas only 9.2% of kilowatt-hours delivered during the first half of 2002 were to shopping customers. Partially offsetting this increase in revenues from returning shopping customers were lower sales to industrial customers due to a decline in economic conditions, as well as reduced revenues from wholesale customers. Milder weather in the first quarter of 2002 resulted in a decrease in kilowatt-hour sales to residential customers in the first six months 2002, compared to the same period in 75 2001. Changes in kilowatt-hour deliveries by customer class during the three and six months ended June 30, 2002, as compared to the same periods in 2001, are summarized in the following table: Changes in Distribution Deliveries Three Months Ended Six Months Ended and Wholesale Generation Sales June 30, 2002 June 30, 2002 ------------------------------------------------------------------------------- Increase (Decrease) Residential............................ 1.1 % (3.6)% Commercial............................. 1.4 % 1.1 % Industrial............................. (4.6)% (6.7)% ---- ---- Total Retail........................... (0.8)% (3.2)% Wholesale.............................. 4.6 % 5.9 % ---- ---- Total ................................. (0.3)% (2.5)% ---- ---- Operating Expenses and Taxes Total operating expenses and taxes increased by $15.2 million in the second quarter of 2002, and $38.3 million in the first half 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 half of 2002, as well as an increase in general taxes. The $3.3 million increase in other operating costs in the second quarter of 2002 compared to the same period in 76 2001 was primarily attributable to higher occupancy rents and employee-related costs. The $4.3 million decrease in other operating costs in the six months ended June 30, 2002 compared to the same period of 2001 was primarily due to the absence of costs related to early retirement programs offered to certain bargaining unit employees in the first quarter of 2001, offset by higher rental costs and pension and other employee related costs. Net Interest Charges Net interest charges decreased by $1.4 million in the second quarter of 2002 and $2.3 million in the first six months of 2002, compared to the same periods in 2001, primarily due to reduced short-term borrowing levels and amortization of fair market value adjustments recorded in connection with the merger. An additional reduction was attributable to the redemption of $30 million of notes in the first quarter of 2002; however, this was partially offset by increased interest on long-term debt due to the issuance of $100 million of notes in September 2001 and $50 million of notes in May 2002 which was used to refinance $30 million of notes in July 2002. Capital Resources and Liquidity ------------------------------- Met-Ed has continuing cash requirements for planned capital expenditures. During the remaining six months of 2002, capital requirements for property additions are expected to be about $33.5 million. These requirements are expected to be satisfied from internal cash and/or short-term credit arrangements. As of June 30, 2002, Met-Ed had about $5.3 million of cash and temporary investments and $71.2 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 June 30, 2002, Met-Ed had the capability to issue up to $62 million of additional FMBs on the basis of property additions and retired bonds. Met-Ed has no restrictions on the issuance of preferred stock. 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 second 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 March 31, 2002.......... $21.3 Settled contracts................................... (0.2) Change in techniques/assumptions.................... -- Decrease in value of existing contracts............. (9.8) ----- Outstanding net asset as of June 30, 2002........... $11.3 ===== 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: 77 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** .... -- -- -- 11.3 11.3 ----- ---- ---- ----- ----- Total ..................... $(0.1) $0.1 $ -- $11.3 $11.3 ===== ==== ==== ===== ===== * Last half 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 and volatilities 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 June 30, 2002. Pennsylvania Regulatory Matters ------------------------------- In June 2001, Met-Ed entered into a settlement agreement with major parties in the combined merger and rate proceedings that, in addition to resolving certain issues concerning the PPUC's approval of FirstEnergy's merger with GPU, also addressed Met-Ed's request for PLR rate relief. Several parties appealed the PPUC decision to the Commonwealth Court of Pennsylvania. On February 21, 2002, the Court affirmed the PPUC decision regarding approval of the 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 denied Met-Ed's related request for rate relief. On March 25, 2002, Met-Ed filed a petition asking the Supreme Court of Pennsylvania to review the Commonwealth Court decision denying Met-Ed the ability to defer costs associated with its PLR obligation. 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. Met-Ed is unable to predict the outcome of these matters. Significant Accounting Policies ------------------------------- Met-Ed 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 financial results. All of Met-Ed'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. Met-Ed's more significant accounting policies are described below. 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 will be reviewed for impairment at least annually. FirstEnergy's most recent review was completed in June 2002. The results of that review indicate that no impairment of the $784.4 million of goodwill is appropriate. Regulatory Accounting Met-Ed is subject to regulation that sets the prices (rates) it is permitted to charge customers based on costs that 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 - $1.3 billion as of June 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. 78 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 must be 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 Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- In June 2001, the Financial Accounting Standards Board issued SFAS 143, "Accounting for Asset Retirement Obligations." The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets with adoption required as of 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 will be recorded if the cost to settle the retirement obligation differs from the carrying amount. Met-Ed has identified various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the second half of 2002. 78
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ---------------------- --------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (In thousands) OPERATING REVENUES........................................ $237,576 | $230,600 $480,396 | $474,427 -------- | -------- -------- | -------- | | | | OPERATING EXPENSES AND TAXES: | | Purchased power........................................ 143,219 | 142,327 289,367 | 311,391 Other operating costs.................................. 38,418 | 37,682 72,218 | 80,765 -------- | -------- -------- | -------- Total operation and maintenance expenses........... 181,637 | 180,009 361,585 | 392,156 Provision for depreciation and amortization............ 14,814 | 15,099 29,645 | 29,628 General taxes.......................................... 14,426 | 12,461 29,456 | 24,151 Income taxes........................................... 6,414 | 4,638 15,586 | 1,302 -------- | -------- -------- | -------- Total operating expenses and taxes................. 217,291 | 212,207 436,272 | 447,237 -------- | -------- -------- | -------- | | OPERATING INCOME.......................................... 20,285 | 18,393 44,124 | 27,190 | | OTHER INCOME.............................................. 789 | 1,414 1,087 | 2,019 -------- | -------- -------- | -------- | | | | INCOME BEFORE NET INTEREST CHARGES........................ 21,074 | 19,807 45,211 | 29,209 -------- | -------- -------- | -------- | | NET INTEREST CHARGES: | | Interest on long-term debt............................. 7,907 | 8,178 16,328 | 16,419 Allowance for borrowed funds used during construction.. (163) | (140) (283) | (284) Deferred interest...................................... (691) | -- (1,442) | -- Other interest expense................................. 834 | 2,744 1,439 | 4,319 Subsidiaries' preferred stock dividend requirements.... 1,942 | 1,835 3,777 | 3,670 -------- | -------- -------- | -------- Net interest charges............................... 9,829 | 12,617 19,819 | 24,124 -------- | -------- -------- | -------- | | NET INCOME................................................ $ 11,245 | $ 7,190 $ 25,392 | $ 5,085 ======== | ======== ======== | ======== The preceding Notes to Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.
79
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, 2002 2001 ---------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: In service................................................................ $1,860,346 $1,845,187 Less--Accumulated provision for depreciation.............................. 656,265 630,957 ---------- ---------- 1,204,081 1,214,230 Construction work in progress- Electric plant.......................................................... 13,720 12,857 ---------- ---------- 1,217,801 1,227,087 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Non-utility generation trusts............................................. 122,162 154,067 Nuclear plant decommissioning trusts...................................... 94,733 96,610 Long-term notes receivable from associated companies...................... 15,515 15,515 Other..................................................................... 6,673 2,265 ---------- ---------- 239,083 268,457 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 20,311 39,033 Receivables- Customers (less accumulated provisions of $11,432,000 and $14,719,000, respectively, for uncollectible accounts)............... 92,933 107,170 Associated companies.................................................... 62,119 40,203 Other................................................................... 16,815 14,842 Prepayments and other..................................................... 21,302 8,605 ---------- ---------- 213,480 209,853 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 682,793 769,807 Goodwill.................................................................. 797,362 797,362 Other..................................................................... 27,469 27,703 ---------- ---------- 1,507,624 1,594,872 ---------- ---------- $3,177,988 $3,300,269 ========== ==========
80
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) June 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................................................... 1,188,190 1,188,190 Accumulated other comprehensive income.................................. 198 1,779 Retained earnings....................................................... 22,187 10,795 ---------- ---------- Total common stockholder's equity................................... 1,316,387 1,306,576 Company-obligated trust preferred securities ............................. 92,107 92,000 Long-term debt............................................................ 471,444 472,400 ---------- ---------- 1,879,938 1,870,976 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 25,783 50,756 Accounts payable- Associated companies.................................................... 122,110 126,390 Other................................................................... 44,092 38,720 Notes payable to associated companies..................................... 103,488 77,623 Accrued taxes............................................................. 9,430 29,255 Accrued interest.......................................................... 12,647 12,284 Other..................................................................... 8,267 10,993 ---------- ---------- 325,817 346,021 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 15,852 21,682 Accumulated deferred investment tax credits............................... 11,385 11,956 Nuclear plant decommissioning costs....................................... 135,999 135,483 Nuclear fuel disposal costs.............................................. 18,617 18,453 Power purchase contract loss liability.................................... 763,489 867,046 Other..................................................................... 26,891 28,652 ---------- ---------- 972,233 1,083,272 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $3,177,988 $3,300,269 ========== ========== The preceding Notes to Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these balance sheets.
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PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Six Months Ended June 30, June 30, ----------------------- ---------------------- 2002 2001 2002 2001 -------- -------- -------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: | | Net income................................................ $ 11,245 | $ 7,190 $ 25,392 | $ 5,085 Adjustments to reconcile net income to net | | cash from operating activities- | | Provision for depreciation and amortization........ 14,814 | 12,660 29,645 | 25,814 Other amortization................................. (595) | 582 187 | 1,044 Deferred costs, net................................ (16,770) | (24,388) (27,185) | (34,755) Deferred income taxes, net......................... 7,980 | 8,085 (1,651) | 8,882 Investment tax credits, net........................ (286) | (286) (571) | (571) Receivables........................................ (21,455) | 6,619 (9,652) | 9,501 Accounts payable................................... 12,915 | 48,397 1,093 | 43,080 Accrued taxes ..................................... (35,087) | 4,620 (19,825) | (5,644) Other.............................................. 15,248 | 3,321 (14,199) | (7,157) -------- | -------- -------- | --------- Net cash provided from (used for) operating | | activities ..................................... (11,991) | 66,800 (16,766) | 45,279 -------- | -------- -------- | --------- | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | New Financing- | | Short-term borrowings, net........................... 65,438 | 22,500 25,865 | 53,200 Contributions from parent............................ -- | 50,000 -- | 50,000 Redemptions and Repayments- | | Long-term debt....................................... 24,973 | -- 24,973 | -- Dividend Payments- | | Common stock......................................... 14,000 | -- 14,000 | -- -------- | -------- -------- | --------- Net cash used for (provided from) financing | | activities ..................................... (26,465) | (72,500) 13,108 | (103,200) -------- | -------- -------- | --------- | | CASH FLOWS FROM INVESTING ACTIVITIES: | | Property additions..................................... 12,623 | 15,149 22,817 | 29,372 Proceeds from non-utility generation trusts............ -- | (7,720) (34,208) | (16,185) Decommissioning trust investments...................... -- | 3 -- | 15 Other.................................................. -- | 852 239 | 4,171 -------- | -------- -------- | --------- Net cash used for (provided from) investing | | activities ..................................... 12,623 | 8,284 (11,152) | 17,373 -------- | -------- -------- | --------- | | Net increase (decrease) in cash and cash equivalents...... 1,851 | 131,016 (18,722) | 131,106 Cash and cash equivalents at beginning of period.......... 18,460 | 670 39,033 | 580 -------- | -------- -------- | --------- Cash and cash equivalents at end of period................ $ 20,311 | $131,686 $ 20,311 | $ 131,686 ======== | ======== ======== | ========= The preceding Notes to Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.
82 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 June 30, 2002, and the related consolidated statements of income and cash flows for each of the three-month and six-month periods ended June 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 August 8, 2002 83 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. Results of Operations --------------------- Operating revenues increased by $7.0 million or 3.0% in the second quarter of 2002, and by $6.0 million or 1.3% in the first half 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. Three Months Ended Six Months Ended Sources of Operating Revenue Changes June 30, 2002 June 30, 2002 -------------------------------------------------------------------------------- Increase (Decrease) (In millions) Change in kilowatt-hour sales due to level of retail customers shopping for generation service ....................... $ 25.0 $ 60.4 Change in other retail kilowatt-hour sales.. (3.3) (8.8) Change in wholesale sales................... (12.7) (40.6) All other changes........................... (2.0) (5.0) ------- ------ Net Increase in Operating Revenues.......... $ 7.0 $ 6.0 ======= ====== Electric Sales In the first half of 2002, a significant reduction in the number of customers receiving their power from alternate suppliers continued to have a positive effect on operating revenues. During the first six months of 2001, 21.5% of kilowatt-hours delivered were to shopping customers, whereas only 4.9% of kilowatt-hours delivered during the first six months of 2002 were to shopping customers. Offsetting this increase in revenues from returning shopping customers were lower sales to wholesale customers during the first half of 2002. A decline in economic conditions resulted in a decrease in sales to industrial customers during the six months ended June 30, 2002; however, conditions began to improve in the quarter ended June 30, 2002, resulting in an increase in industrial sales during that period. Changes in kilowatt-hour deliveries by customer class during the three and six months periods ended June 30, 2002, as compared to the same periods in 2001, are summarized in the following table: Changes in Distribution Deliveries Three Months Ended Six Months Ended and Wholesale Generation Sales June 30, 2002 June 30, 2002 ------------------------------------------------------------------------------ Increase (Decrease) Residential............................. 1.5% (1.5)% Commercial.............................. 2.0% 0.9 % Industrial.............................. 9.3% (4.9)% ----- ----- Total Retail............................ 4.2% (1.8)% Wholesale............................... (56.9)% (71.9)% ----- ----- Total .................................. (2.5)% (10.7)% ----- ----- Operating Expenses and Taxes Total operating expenses and taxes increased by $5.1 million in the second quarter of 2002 compared to the same period in 2001, as a result of a slight increase in operation and maintenance expenses, as well as higher general taxes. 84 Total operating expenses and taxes decreased by $11.0 million in the first six months of 2002 compared to the same period in 2001. A $22.0 million decrease in purchased power costs during this period was primarily due to the absence in 2002 of a $16.0 million charge related to the termination of a wholesale energy contract in 2001. A decrease of $8.5 million during the same period was primarily attributable to the absence of costs related to early retirement programs offered to certain bargaining unit employees during the first quarter of 2001. These decreases were partially offset by an increase of $5.3 million in general taxes in the first six months of 2002 compared to the same period in 2001, as well as higher pension and other employee related costs. Net Interest Charges Net interest charges decreased by $2.8 million in the second quarter of 2002, and $4.3 million in the first half of 2002, compared to the same periods in 2001. The decreases reflect higher interest deferrals related to Penelec's deferred provider of last resort costs, and reduced short-term borrowing levels. Capital Resources and Liquidity ------------------------------- Penelec has continuing cash requirements for planned capital expenditures and maturing debt. During the remaining six months of 2002, capital requirements for property additions and capital leases are expected to be about $31.6 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. As of June 30, 2002, Penelec had about $20.3 million of cash and temporary investments and $103.5 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 June 30, 2002, Penelec had the capability to issue up to $463 million of additional FMBs on the basis of property additions and retired bonds. Penelec has no restrictions on the issuance of preferred stock. 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 second 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 March 31, 2002.......... $10.5 Settled contracts................................... (0.2) Change in techniques/assumptions.................... -- Decrease in value of existing contracts............. (4.6) ----- Outstanding net asset as of June 30, 2002........... $ 5.7 ===== 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, 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 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: 85 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** ... -- -- -- 5.7 5.7 ----- ---- ---- ---- ---- Total .................... $(0.1) $0.1 $ -- $5.7 $5.7 ===== ==== ==== ==== ==== * For the last half 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 and volatilities 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 June 30, 2002. Pennsylvania Regulatory Matters ------------------------------- In June 2001, Penelec entered into a settlement agreement with major parties in the combined merger and rate proceedings that, in addition to resolving certain issues concerning the PPUC's approval of FirstEnergy's merger with GPU, also addressed Penelec's request for PLR rate relief. Several parties appealed the PPUC decision to the Commonwealth Court of Pennsylvania. On February 21, 2002, the Court affirmed the PPUC decision regarding approval of the 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 denied Penelec's related request for rate relief. On March 25, 2002, Penelec filed a petition asking the Supreme Court of Pennsylvania to review the Commonwealth Court decision denying Penelec the ability to defer costs associated with its PLR obligation. 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. Penelec is unable to predict the outcome of these matters. Significant Accounting Policies ------------------------------- Penelec 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 financial results. All of Penelec'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. Penelec's more significant accounting policies are described below. 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 will be reviewed for impairment at least annually. FirstEnergy's most recent review was completed in June 2002. The results of that review indicate that no impairment of Penelec's $797.4 million of goodwill is appropriate. Regulatory Accounting Penelec is subject to regulation that sets the prices (rates) it is permitted to charge customers based on costs that 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 - $682.8 million as of June 30, 2002. Penelec 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. 86 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 must be 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 Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- In June 2001, the Financial Accounting Standards Board issued SFAS 143, "Accounting for Asset Retirement Obligations." The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets with adoption required as of 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 will be recorded if the cost to settle the retirement obligation differs from the carrying amount. Penelec has identified various applicable legal obligations as defined under the new standard and expects to complete an analysis of their financial impact in the second half of 2002. 87 PART II. OTHER INFORMATION --------------------------- Item 4. Submission of Matters to a Vote of Security Holders --------------------------------------------------- (a) The annual meeting of FirstEnergy shareholders was held on May 21, 2002. (b) At this meeting, the following persons were elected to FirstEnergy's Board of Directors: Number of Votes ------------------------------ For Withheld ----------- --------- Anthony J. Alexander 249,064,230 3,900,177 H. Peter Burg 249,016,232 3,948,175 Russell W. Maier 248,971,447 3,992,960 Robert N. Pokelwaldt 248,926,056 4,038,351 Jesse T. Williams, Sr. 249,446,265 3,518,142 (c) At this meeting, an amendment to the Executive and Director Incentive Compensation Plan was approved (passage required a majority of votes cast): Number of Votes ---------------------------------------------- For Against Abstentions ----------- ---------- ----------- 211,599,033 37,047,370 4,318,004 (d) At this meeting, a shareholder proposal designed to result in the election of the entire Board of Directors each year was rejected (passage required 80% of the 297,636,276 common shares outstanding): Number of Votes ---------------------------------------------------------------- Broker For Against Abstentions Non-Votes ----------- ---------- ----------- --------- 127,437,897 87,573,561 5,452,837 32,500,112 (e) At this meeting, a shareholder proposal to reinstate simple-majority vote on all issues that are submitted to shareholder vote was rejected (passage required 80% of the 297,636,276 common shares outstanding): Number of Votes ----------------------------------------------------------------- Broker For Against Abstentions Non-Votes ----------- ---------- ----------- --------- 135,678,057 79,163,575 5,626,478 32,496,297 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 88 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 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 ----------- Four reports on Form 8-K were filed since March 31, 2002. A report dated April 18, 2002 reported a change in the registrant's certifying accountant. A report dated May 9, 2002 reported the completion of the Avon Energy Partners Holdings sale. A report dated May 24, 2002 reported the purchase of an unused replacement reactor vessel head for the Davis-Besse Nuclear Power Station. A report dated August 1, 2002 reported two JCP&L rate filings with the New Jersey Board of Public Utilities. OE, Penn, Met-Ed and Penelec ---------------------------- OE, Penn, Met-Ed and Penelec each filed one report on Form 8-K since March 31, 2002. A report dated April 18, 2002 reported a change in the registrant's certifying accountant. CEI and TE ---------- CEI and TE each filed two reports on Form 8-K since March 31, 2002. A report dated April 18, 2002 reported a change in the registrant's certifying accountant. A report dated May 24, 2002 reported the purchase of an unused replacement reactor vessel head for the Davis-Besse Nuclear Power Station. JCP&L ----- JCP&L filed two reports on Form 8-K since March 31, 2002. A report dated April 18, 2002 reported a change in the registrant's certifying accountant. A report dated August 1, 2002 reported two JCP&L rate filings with the New Jersey Board of Public Utilities. 89 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. August 8, 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 90