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 March 31, 2003 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 by check mark whether each registrant is an accelerated filer ( as defined in Rule 12b-2 of the Act): 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: <TABLE> <CAPTION> OUTSTANDING CLASS AS OF MAY 9, 2003 ----- ----------------- <S> <C> 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 </TABLE> 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.................................. 1-13 FirstEnergy Corp. Consolidated Statements of Income.............................. 14 Consolidated Balance Sheets.................................... 15-16 Consolidated Statements of Cash Flows.......................... 17 Report of Independent Accountants.............................. 18 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 19-38 Ohio Edison Company Consolidated Statements of Income.............................. 39 Consolidated Balance Sheets.................................... 40-41 Consolidated Statements of Cash Flows.......................... 42 Report of Independent Accountants.............................. 43 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 44-51 The Cleveland Electric Illuminating Company Consolidated Statements of Income.............................. 52 Consolidated Balance Sheets.................................... 53-54 Consolidated Statements of Cash Flows.......................... 55 Report of Independent Accountants.............................. 56 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 57-64 The Toledo Edison Company Consolidated Statements of Income.............................. 65 Consolidated Balance Sheets.................................... 66-67 Consolidated Statements of Cash Flows.......................... 68 Report of Independent Accountants.............................. 69 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 70-77 Pennsylvania Power Company Statements of Income........................................... 78 Balance Sheets................................................. 79-80 Statements of Cash Flows....................................... 81 Report of Independent Accountants.............................. 82 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 83-88 Jersey Central Power & Light Company Consolidated Statements of Income.............................. 89 Consolidated Balance Sheets.................................... 90-91 Consolidated Statements of Cash Flows.......................... 92 Report of Independent Accountants.............................. 93 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 94-101
TABLE OF CONTENTS (Cont'd) Pages Metropolitan Edison Company Consolidated Statements of Income.............................. 102 Consolidated Balance Sheets.................................... 103-104 Consolidated Statements of Cash Flows.......................... 105 Report of Independent Accountants.............................. 106 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 107-114 Pennsylvania Electric Company Consolidated Statements of Income.............................. 115 Consolidated Balance Sheets.................................... 116-117 Consolidated Statements of Cash Flows.......................... 118 Report of Independent Accountants.............................. 119 Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 120-127 Controls and Procedures............................................. 128 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. JCP&L, Met-Ed and Penelec were acquired in a merger (which was effective November 7, 2001) 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. FirstEnergy's consolidated financial statements also include its other principal subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FSG); 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. FSG is the parent company of several heating, ventilating, air conditioning and energy management companies, and MYR is a utility infrastructure construction service company. MARBEL is a fully integrated natural gas company. GPU Capital owns and operates electric distribution systems in foreign countries (see Note 3) and GPU Power owns and operates generation facilities in foreign countries. FECO and GPUS provide legal, financial and other corporate support services to affiliated FirstEnergy companies. Significant intercompany transactions have been eliminated. The Companies follow the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC), the New Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC). The 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 and Amendment No. 1 on Form 10-K/A for the year ended December 31, 2002 for FirstEnergy and the Companies. 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, as discussed further in Note 5. Preferred Securities The sole assets of the CEI subsidiary trust that is the obligor on the preferred securities included in FirstEnergy's and CEI's capitalization are $103,093,000 principal amount of 9% Junior Subordinated Debentures of CEI due December 31, 2006. Met-Ed and Penelec each formed statutory business trusts for the issuance of $100 million each of preferred securities due 2039. However, ownership of the respective Met-Ed and Penelec trusts is through separate wholly-owned limited partnerships, of which a wholly-owned subsidiary of each company is the sole general partner. In these transactions, the sole assets and sources of revenues of each trust are the preferred securities of the applicable limited partnership, whose sole assets are the 7.35% and 7.34% subordinated debentures (aggregate principal amount of $103.1 million each) 1 of Met-Ed and Penelec, respectively. In each case, the applicable parent company has effectively provided a full and unconditional guarantee of the trust's obligations under the preferred securities. Securitized Transition Bonds In June 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of JCP&L, sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. JCP&L does not own 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 represents the irrevocable right of a utility company to charge, collect and receive from its customers, through a non-bypassable transition bond charge, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the transition bond charge, pursuant to a servicing agreement with the Issuer. JCP&L is entitled to a quarterly servicing fee of $100,000 that is payable from transition bond charge collections. Derivative Accounting FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including electricity, natural gas and coal. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. FirstEnergy uses derivatives to hedge the risk of price and interest rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The maximum periods over which the variability of electricity and natural gas cash flows are hedged are two and three years, respectively. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. Also, gains and losses are included in net income when ineffectiveness occurs on certain natural gas hedges. FirstEnergy entered into interest rate derivative transactions during 2001 to hedge a portion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from hedges of anticipated interest payments on acquisition debt will be included in net income over the periods that hedged interest payments are made - 5, 10 and 30 years. Gains and losses from derivative contracts are included in other operating expenses. The current net deferred loss of $105.8 million included in Accumulated Other Comprehensive Loss (AOCL) as of March 31, 2003, for derivative hedging activity, as compared to the December 31, 2002 balance of $110.2 million in net deferred losses, resulted from a $8.8 million reduction related to current hedging activity and a $4.4 million increase due to net hedge gains included in earnings during the three months ended March 31, 2003. Approximately $20.2 million (after tax) of the current net deferred loss on derivative instruments in AOCL is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. However, the fair value of these derivative instruments will fluctuate from period to period based on various market factors and will generally be more than offset by the margin on related sales and revenues. FirstEnergy also entered into fixed-to-floating interest rate swap agreements during 2002 to increase the variable-rate component of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues-protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options and interest payment dates match those of the underlying obligations resulting in no ineffectiveness in these hedge positions. The swap agreements consummated in the first quarter of 2003 are based on a notional principal amount of $200 million. As of March 31, 2003, the notional amount of FirstEnergy's fixed-for-floating rate interest rate swaps totaled $700 million. FirstEnergy engages in the trading of commodity derivatives and periodically experiences net open positions. FirstEnergy's risk management policies limit the exposure to market risk from open positions and require daily reporting to management of potential financial exposures. Comprehensive Income Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity, except those resulting from transactions with common stockholders. As of March 31, 2003, FirstEnergy's AOCL was approximately $657.4 million as compared to the December 31, 2002 balance of $663.2 million. Comprehensive income for the first quarter of 2003 and 2002 are shown in the following table: 2
Three months ended March 31, ---------------------------- 2003 2002 ---- ---- (In thousands) Net income................................. $240,985 $116,493 Other comprehensive income, net of tax: Derivative hedge transactions............ 4,341 35,844 All other................................ 1,484 730 -------- -------- Comprehensive income....................... $246,810 $153,067 ======== ======== Stock-Based Compensation FirstEnergy applies the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans. No material stock-based employee compensation expense is reflected in net income as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The effects of applying fair value accounting to FirstEnergy's stock options would be to reduce net income and earnings per share. The following table summarizes this effect. Three Months Ended March 31, ------------------ 2003 2002 (In thousands) Net Income, as reported............. $240,985 $116,493 Add back compensation expense reported in net income, net of tax (based on APB 25)................. 43 43 Deduct compensation expense based upon fair value, net of tax....... (2,983) (1,402) - -------------------------------------------------------------- Adjusted net income................. $238,045 $115,134 ------------------------------------------------------------- Earnings Per Share of Common Stock - Basic As Reported..................... $0.82 $0.40 Adjusted........................ $0.81 $0.39 Diluted As Reported..................... $0.82 $0.40 Adjusted........................ $0.81 $0.39 Change in Previously Reported Income Statement Classification - FirstEnergy recorded an increase to income during the three months ended March 31, 2002 of $31.7 million (net of income taxes of $13.6 million) relative to a decision to retain an interest in the Avon Energy Partners Holdings (Avon) business previously classified as held for sale - see Note 3. This amount represents the aggregate results of operations of Avon for the period this business was held for sale. It was previously reported on the Consolidated Statement of Income as the cumulative effect of a change in accounting. In April 2003, it was determined that this amount should instead have been classified in operations. As further discussed in Note 3, the decision to retain Avon was made in the first quarter of 2002 and Avon's results of operations for that quarter have been classified in their respective revenue and expense captions on the Consolidated Statement of Income. This change in classification had no effect on previously reported net income. The effects of this change on the Consolidated Statement of Income previously reported for the three months ended March 31, 2002 are as follows: 3
<TABLE> <CAPTION> Three Months Ended March 31, 2002 --------------------------------- As Previously Revised Presented Presentation - -------------------------------------------------------------------------------------------------------------------- <S> <C> <C> Revenues (Note 5)............................................................... $2,802,157 $2,853,278 Expenses (Note 5).............................................................. 2,376,713 2,363,634 ---------- ---------- Income before interest and income taxes......................................... 425,444 489,644 Net interest charges............................................................ 259,822 278,722 Income taxes.................................................................... 80,829 94,429 ---------- ---------- Income before cumulative effect of accounting change............................ 84,793 116,493 Cumulative effect of accounting change.......................................... 31,700 -- ---------- ---------- Net income...................................................................... $ 116,493 $ 116,493 ========== ========== Basic Earnings Per Share: Income before cumulative effect of accounting change......................... $0.29 $0.40 Cumulative effect of accounting change....................................... 0.11 -- ----- ----- Net income................................................................... $0.40 $0.40 ===== ===== Diluted Earnings Per Share: Income before cumulative effect of accounting change......................... $0.29 $0.40 Cumulative effect of accounting change....................................... 0.11 -- ----- ----- Net income................................................................... $0.40 $0.40 ===== ===== </TABLE> 2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES: Capital Expenditures FirstEnergy's current forecast reflects expenditures of approximately $3.1 billion (OE-$268 million, CEI-$312 million, TE-$169 million, Penn-$123 million, JCP&L-$462 million, Met-Ed-$288 million, Penelec-$328 million, ATSI-$131 million, FES-$823 million and other subsidiaries-$147 million) for property additions and improvements from 2003-2007, of which approximately $727 million (OE-$86 million, CEI-$96 million, TE-$54 million, Penn-$53 million, JCP&L-$102 million, Met-Ed-$53 million, Penelec-$54 million, ATSI-$25 million, FES-$124 million and other subsidiaries-$80 million) is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $485 million (OE-$55 million, CEI-$53 million, TE-$34 million, Penn-$42 million and FES-$301 million), of which approximately $69 million (OE-$23 million, CEI-$15 million, TE-$12 million and Penn-$19 million) applies to 2003. Guarantees and Other Assurances As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of March 31, 2003, outstanding guarantees and other assurances aggregated $960.2 million. FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood that such parental guarantees of $872.7 million as of March 31, 2003 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $25.8 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions. Various energy supply contracts contain credit enhancement provisions in the form of cash collateral or letters of credit in the event of a reduction in credit rating below investment grade. These provisions vary and typically require more than one rating reduction to fall below investment grade by Standard & Poor's or Moody's Investors Service to trigger additional collateralization by FirstEnergy. As of March 31, 2003, rating-contingent collateralization totaled $61.7 million. FirstEnergy monitors these collateralization provisions and updates its total exposure monthly. 4
Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $159 million, which is included in the construction forecast provided under "Capital Expenditures" for 2003 through 2007. The Companies are required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies believe they are in compliance with the current SO2 and nitrogen 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 SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals for the D.C. Circuit found constitutional and other defects in the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating ultra-fine particulates but found defects in the new NAAQS rules for ozone and decided that the EPA must revise those rules. The future cost of compliance with these regulations may be substantial and will depend if and how they are ultimately implemented by the states in which the Companies operate affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio for which hearings began in February 2003. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of these proceedings, FirstEnergy believes the Sammis Plant is in full compliance with the Clean Air Act and the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. The Companies have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable 5
societal benefits charge. The Companies have total accrued liabilities aggregating approximately $53.9 million (JCP&L-$47.1 million, CEI-$2.5 million, TE-$0.2 million, Met-Ed-$0.2 million, Penelec-$0.3 million and other-$3.6 million) as of March 31, 2003. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy believes it is in material compliance with existing regulations but is unable to predict whether environmental regulations will change and what, if any, the effects of such change would be. Other Commitments and Contingencies GPU made significant investments in foreign businesses and facilities through its GPU Capital and GPU Power subsidiaries. Although FirstEnergy attempts to mitigate its risks related to foreign investments, it faces additional risks inherent in operating in such locations, including foreign currency fluctuations. EI Barranquilla, a wholly owned subsidiary of GPU Power, is a 28.67% equity investor in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA), which owns a Colombian independent power generation project. GPU Power is committed through September 30, 2003, under certain circumstances, to make additional standby equity contributions to TEBSA of $21.3 million, which FirstEnergy has guaranteed. The total outstanding senior debt of the TEBSA project is $239 million as of March 31, 2003. 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. FirstEnergy provided the TEBSA project lenders a $50 million letter of credit (LOC) issued by Bank One under FirstEnergy's existing $250 million LOC capacity available as part of the $1.5 billion FirstEnergy credit facility to obtain TEBSA lender consent to abandon its Argentina operations, GPU Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa) (see Note 3 below). 3 - DIVESTITURES: INTERNATIONAL OPERATIONS- FirstEnergy had identified certain former GPU international operations for divestiture within one year of the merger. These operations constitute individual "lines of business" as defined in APB Opinion (APB) No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," with physically and operationally separable activities. Application of Emerging Issues Task Force ( EITF) Issue No. 87-11, "Allocation of Purchase Price to Assets to Be Sold," required that expected, pre-sale cash flows, including incremental interest costs on related acquisition debt, of these operations be considered part of the purchase price allocation. Accordingly, subsequent to the merger date, results of operations and incremental interest costs related to these international subsidiaries were not included in FirstEnergy's 2001 Consolidated Statement of Income. Additionally, assets and liabilities of these international operations had been segregated under separate captions on the Consolidated Balance Sheet as of December 31, 2001 as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale." Upon completion of its merger with GPU, FirstEnergy accepted an October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase Avon, FirstEnergy's wholly owned holding company for Midlands Electricity plc, for $2.1 billion (including the assumption of $1.7 billion of debt). The transaction closed on May 8, 2002 and reflected the March 2002 modification of Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest in Avon for approximately $1.9 billion (including the assumption of $1.7 billion of debt). Proceeds to FirstEnergy included $155 million in cash and a note receivable for approximately $87 million (representing the present value of $19 million per year to be received over six years beginning in 2003) from Aquila for its 79.9 percent interest. FirstEnergy and Aquila together own all of the outstanding shares of Avon through a jointly owned subsidiary, with each company having an ownership voting interest. Originally, in accordance with applicable accounting guidance, the earnings of those foreign operations were not recognized in current earnings from the date of the GPU acquisition. However, as a result of the decision to retain an ownership interest in Avon in the quarter ended March 31, 2002, EITF Issue No. 90-6, "Accounting for Certain Events Not Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be Sold" required FirstEnergy to reallocate the purchase price of GPU based on amounts as of the purchase date as if Avon had never been held for sale, including reversal of the effects of having applied EITF Issue No. 87-11, to the transaction. The effect of reallocating the purchase price and reversal of the effects of EITF Issue No. 87-11, including the allocation of capitalized interest, has been reflected in the Consolidated Statement of Income for the quarter ended March 31, 2002 by reclassifying certain revenue and expense amounts related to activity during the quarter ended March 31, 2002 to their respective income statement classifications. See Note 1 for the effects of the change in classification. In the fourth quarter of 2002, 6
FirstEnergy recorded a $50 million charge ($32.5 million net of tax) to reduce the carrying value of its remaining 20.1 percent interest. GPU's former Argentina operations were also identified by FirstEnergy for divestiture within one year of the merger. FirstEnergy determined the fair value of 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 included currency devaluation, restrictions on repatriation of cash, and the anticipation of future asset sales in that region by competitors. FirstEnergy did not reach a definitive agreement to sell Emdersa as of December 31, 2002. Therefore, these assets were no longer classified as "Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2002. Additionally, under EITF Issue No. 90-6, FirstEnergy recorded in the fourth quarter of 2002 a one-time, non-cash charge included as a "Cumulative Adjustment for Retained Businesses Previously Held for Sale" on its 2002 Consolidated Statement of Income related to Emdersa's cumulative results of operations from November 7, 2001 through September 30, 2002. The amount of this one-time, after-tax charge was $93.7 million, or $0.32 per share of common stock (comprised of $108.9 million in currency transaction losses arising principally from U.S. dollar denominated debt, offset by $15.2 million of operating income). In October 2002, FirstEnergy began consolidating the results of Emdersa's operations in its financial statements. In addition to the currency transaction losses of $108.9 million, FirstEnergy also recognized a currency translation adjustment (CTA) in other comprehensive income (OCI) of $91.5 million as of December 31, 2002, which reduced FirstEnergy's common stockholders' equity. This adjustment represents the impact of translating Emdersa's financial statements from its functional currency to the U.S. dollar for GAAP financial reporting. On April 18, 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. As a result of the abandonment, FirstEnergy will recognize a one-time, non-cash charge of $63 million, or $0.21 per share of common stock in the second quarter of 2003. This charge is the result of realizing the CTA losses through its current period earnings ($90 million, or $0.30 per share), partially offset by the gain recognized from eliminating its investment in Emdersa ($27 million, or $0.09 per share). Since FirstEnergy had previously recorded $90 million of CTA adjustments in OCI, the net effect of the $63 million charge will be an increase in common stockholders' equity of $27 million. The $63 million charge does not include the anticipated income tax benefits related to the abandonment. These tax benefits will be fully reserved during the second quarter. FirstEnergy anticipates tax benefits of approximately $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million of tax benefits would reduce goodwill recognized in connection with the acquisition of GPU. SALE OF GENERATING ASSETS- In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 megawatts (MW) to NRG Energy Inc. On August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves the right to pursue legal action against NRG, its affiliate and its parent, Xcel Energy for damages, based on the anticipatory breach of the agreement. On February 25, 2003, the U.S. Bankruptcy Court in Minnesota approved FirstEnergy's request for arbitration against NRG. In December 2002, FirstEnergy decided to retain ownership of these plants after reviewing other bids it subsequently received from other parties who had expressed interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, it reflected approximately $74 million ($43 million net of tax) of previously unrecognized depreciation and other transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statement of Income. 4 - REGULATORY MATTERS: In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in the Companies' respective state regulatory plans: o allowing the Companies' electric customers to select their generation suppliers; o establishing provider of last resort (PLR) obligations to customers in the Companies' service areas; o allowing recovery of potentially stranded investment (sometimes referred to as transition costs); 7
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 In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. In July 2000, the PUCO approved FirstEnergy's transition plan for OE, CEI and TE (Ohio Companies) as modified by a settlement agreement with major parties to the transition plan. The application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" to OE's generation business and the nonnuclear generation businesses of CEI and TE was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $4.0 billion net of deferred income taxes (OE-$1.6 billion, CEI-$1.6 billion and TE-$0.8 billion) and transition costs related to regulatory assets as filed of $2.9 billion net of deferred income taxes (OE-$1.0 billion, CEI-$1.4 billion and TE-$0.5 billion), with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.4 billion, net of deferred income taxes, (OE-$1.0 billion, CEI-$0.2 billion and TE-$0.2 billion) of impaired generating assets recognized as regulatory assets as described further below, $2.4 billion, net of deferred income taxes, (OE-$1.2 billion, CEI-$0.4 billion and TE-$0.8 billion) of above market operating lease costs and $0.8 billion, net of deferred income taxes, (CEI-$0.5 billion and TE-$0.3 billion) of additional plant costs that were reflected on CEI's and TE's regulatory financial statements. Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 MW of generation capacity through 2005 at established prices for sales to the Ohio Companies' retail customers. Customer prices are frozen through the five-year market development period, which runs through the end of 2005, except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Ohio Companies were authorized increases in annual revenues aggregating approximately $50 million (OE-$41 million, CEI-$4 million and TE-$5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation. FirstEnergy's Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be accomplished by extending the respective transition cost recovery period. If the customer shopping goals established in the agreement had not been achieved by the end of 2005, the transition cost recovery periods could have been shortened for OE, CEI and TE to reduce recovery by as much as $500 million (OE - $250 million, CEI - $170 million and TE - $80 million). The Ohio Companies achieved all of their required 20% customer shopping goals in 2002. Accordingly, FirstEnergy believes that there will be no regulatory action reducing the recoverable transition costs. New Jersey JCP&L's 2001 Final Decision and Order (Final Order) with respect to its rate unbundling, stranded cost and restructuring filings confirmed rate reductions set forth in its 1999 Summary Order, which remain in effect at increasing levels through July 2003. The Final Order also confirmed the establishment of a non-bypassable societal benefits charge (SBC) to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable market transition charge (MTC) primarily to recover stranded costs. The NJBPU has deferred making a final determination of the net proceeds and stranded costs related to prior generating asset divestitures until JCP&L's request for an Internal Revenue Service (IRS) ruling regarding the treatment of associated federal income tax benefits is acted upon. Should the IRS ruling support the return of the tax benefits to customers, there would be no effect to FirstEnergy's or JCP&L's net income since the contingency existed prior to the merger. 8
In addition, the Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. In 2002, JCP&L received NJBPU authorization to issue $320 million of transition bonds to securitize the recovery of these costs and which 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 the transition bonds through its wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 - those bonds are recognized on the Consolidated Balance Sheet. JCP&L's PLR obligation to provide basic generation service (BGS) to non-shopping customers is supplied almost entirely from contracted and open market purchases. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under nonutility generation (NUG) agreements exceed amounts collected through BGS and MTC rates. As of March 31, 2003, the accumulated deferred cost balance totaled approximately $530 million. The NJBPU also allowed securitization of JCP&L's deferred balance to the extent permitted by law upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization. Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L submitted two rate filings with the NJBPU in August 2002. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization discussed above. Hearings began in February 2003. On March 18, 2003, a report prepared by independent auditors addressing costs deferred by JCP&L from August 1, 1999 through July 31, 2002, was transmitted to the Office of Administrative Law, where JCP&L's rate case is being heard. While the auditors concluded that JCP&L's energy procurement strategy and process was reasonable and prudent, they identified potential disallowances approximating $17 million. The report subjected $436 million of deferred costs to a retrospective prudence review during a period of extreme price uncertainty and volatility in the energy markets. Although JCP&L disagrees with the potential disallowances, it is pleased with the report's major conclusions and overall tone. Hearings concluded on April 28, 2003, and initial briefs were filed on May 7, 2003. The JCP&L brief supports its two rate filings requesting an aggregate rate increase of approximately $122 million in base electric rates and the recovery of deferred costs based on the securitization methodology discussed above. If the securitization methodology is not allowed, then JCP&L has requested deferred cost recovery over a four-year period with a return on the unamortized deferred cost balance. This alternative would increase the overall rate request to approximately $246 million. JCP&L strongly disagrees with many of the positions taken by NJBPU Staff. The Staff's position would result in a $119 million estimated annual earnings decrease related to the electricity delivery charge. In addition, the Staff recommended disallowing approximately $153 million of deferred energy costs which would result in a one-time pre-tax charge against earnings of $153 million (or $0.31 per share of common stock). JCP&L will respond to the Staff's position in its Reply Brief which is due on May 21, 2003. The Administrative Law Judge's recommended decision is due by the end of June 2003 and the NJBPU's subsequent decision is due in July 2003. In 1997, the NJBPU authorized JCP&L to recover from customers, subject to possible refund, $135 million of costs incurred in connection with a 1996 buyout of a power purchase agreement. JCP&L has recovered the full $135 million; the NJBPU has established a procedural schedule to take further evidence with respect to the buyout to enable it to make a final prudence determination contemporaneously with the resolution of the pending rate case. In December 2001, the NJBPU authorized the auctioning of BGS for the period from August 1, 2002 through July 31, 2003 to meet the electricity demands of all customers who have not selected an alternative supplier. The auction results were approved by the NJBPU in February 2002, removing JCP&L's BGS obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In February 2003, the NJBPU approved the BGS auction results for the period beginning August 1, 2003. The auction covered a fixed price bid (applicable to all residential and smaller commercial and industrial customers) and an hourly price bid (applicable to all large industrial customers) process. JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balances. Pennsylvania The PPUC authorized 1998 rate restructuring plans for Penn, Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Similar to JCP&L's situation, if the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income since the contingency existed prior to the merger. 9
As a result of their generating asset divestitures, Met-Ed and Penelec obtained their supply of electricity to meet their PLR obligations almost entirely from contracted and open market purchases. In 2000, Met-Ed and Penelec filed a petition with the PPUC seeking permission to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates; the PPUC subsequently consolidated this petition in January 2001 with the FirstEnergy/GPU merger proceeding. In June 2001, the PPUC entered orders approving the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the merger and provided Met-Ed and Penelec PLR deferred accounting treatment for energy costs. The PPUC permitted Met-Ed and Penelec to defer for future recovery the difference between their actual energy costs and those reflected in their capped generation rates, retroactive to January 1, 2001. Correspondingly, in the event that energy costs incurred by Met-Ed and Penelec would be below their respective capped generation rates, that difference would have reduced costs that had been deferred for recovery in future periods. This PLR deferral accounting procedure was denied in a court decision discussed below. Met-Ed's and Penelec's PLR obligations extend through December 31, 2010; during that period competitive transition charge (CTC) revenues would have been applied to their stranded costs. Met-Ed and Penelec would have been permitted to recover any remaining stranded costs through a continuation of the CTC after December 31, 2010 through no later than December 31, 2015. Any amounts not expected to be recovered by December 31, 2015 would have been written off at the time such nonrecovery became probable. Several parties had filed Petitions for Review in June and July 2001 with the Commonwealth Court of Pennsylvania regarding the June 2001 PPUC orders. On February 21, 2002, the Court affirmed the PPUC decision regarding the FirstEnergy/GPU merger, remanding the decision to the PPUC only with respect to the issue of merger savings. The Court reversed the PPUC's decision regarding the PLR obligations of Met-Ed and Penelec, and rejected those parts of the settlement that permitted the companies to defer for accounting purposes the difference between their wholesale power costs and the amount that they collect from retail customers. FirstEnergy and the PPUC each filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court on March 25, 2002, asking it to review the Commonwealth Court decision. Also on March 25, 2002, Citizens Power filed a motion seeking an appeal of the Commonwealth Court's decision to affirm the FirstEnergy and GPU merger with the Pennsylvania Supreme Court. In September 2002, FirstEnergy established reserves for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287.1 million. The reserves reflected the potential adverse impact of a pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court ruling. FirstEnergy recorded an aggregate non-cash charge to income of $55.8 million ($32.6 million net of tax), or $0.11 per share of common stock, for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million. On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the PPUC's order approving the merger between FirstEnergy and GPU, let stand the Commonwealth Court's denial of PLR rate relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. On April 2, 2003, the PPUC remanded the merger savings issue to the Office of Administrative Law for hearings and directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court's order on the Settlement Stipulation by May 2, 2003. Because FirstEnergy had already reserved for the deferred energy costs and FES has largely hedged the anticipated PLR energy supply requirements for Met-Ed and Penelec through 2005 as discussed further below, FirstEnergy, Met-Ed and Penelec believe that the disallowance of continued CTC recovery of PLR costs will not have a future adverse financial impact during that period. Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to their FES affiliate through a wholesale power sale agreement. The PLR sale currently runs through December 2003 and will be automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES assumed the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at or below the shopping credit for their uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of Met-Ed's and Penelec's unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previously allowed under the PPUC's order. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and amounts recovered through their capped generation rates. 5 - NEW ACCOUNTING STANDARDS: In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143, "Accounting for Asset Retirement Obligations." The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation (ARO) 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 10
depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead, if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003 asset retirement costs were recorded in the amount of $602 million as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The ARO liability at the date of adoption was $1.109 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. At December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.232 billion, including unrealized gains on the decommissioning trust funds of $12 million. FirstEnergy expects substantially all nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn would be recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for these operating companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $174.7 million increase to income, or a $102.1 million increase net of tax, or $0.35 per share of common stock (basic and diluted). The $12 million of unrealized gains, $7 million net of tax, included in the decommissioning liability balances at December 31, 2002 was offset against OCI upon adoption of SFAS 143. FirstEnergy recorded an ARO for nuclear decommissioning ($1.096 billion) of the Beaver Valley 1, Beaver Valley 2, Davis-Besse, Perry, and TMI-2 nuclear generation facilities with the remaining ARO related to Bruce Mansfield's sludge impoundment facilities and two coal ash disposal sites. The Company maintains nuclear decommissioning trust funds, which had balances at March 31, 2003 of $1.061 billion. This number represents the fair value of the assets that are legally restricted for purposes of settling the nuclear decommissioning ARO. The following table provides the beginning and ending aggregate carrying amount of the ARO and the changes to the balance for the period of January 1, 2003 through March 31, 2003.
ARO Reconciliation --------------------------------------------------------------------- (millions) Beginning balance as of January 1, 2003 ................. $1,109 Liabilities incurred in the current period............. -- Liabilities settled in the current period.............. -- Accretion expense...................................... 18 Revisions in estimated cash flows........................ -- -------------------------------------------------------------------- Ending balance as of March 31, 2003...................... $1,127 -------------------------------------------------------------------- The following table provides on an adjusted basis the year-end balance of the ARO related to nuclear decommissioning and sludge impoundment for 2002, as if SFAS 143 had been adopted on January 1, 2002.
Adjusted ARO Reconciliation --------------------------------------------------------------------- (millions) Beginning balance as of January 1, 2002.................. $1,042 Accretion 2002........................................... 67 -------------------------------------------------------------------- Ending balance as of December 31, 2002 ................. $1,109 -------------------------------------------------------------------- In accordance with SFAS 143 FirstEnergy ceased the accounting practice of depreciating non-regulated generation assets using a cost of removal component in the depreciation rates that are applied to the generation assets. This practice recognizes accumulated depreciation in excess of the historical cost of an asset, because the removal cost exceeds the estimated salvage value. The change in accounting resulted in a $60 million credit to income as part of the SFAS 143 cumulative effect adjustment. Beginning in 2003 depreciation rates applied to non-regulated generation assets will exclude the cost of removal component and cost of removal will be charged to income rather than charged to the accumulated provision for depreciation. In accordance with SFAS 71, the regulated plant assets will continue the accounting practice of depreciating assets using a cost of removal component in the depreciation rates. The net removal cost credit balance included in the accumulated provision for regulated assets at March 31, 2003 is $296.1 million. The following table provides on an adjusted basis the effect on income, as if the accounting for SFAS 143 had been applied in the first quarter 2002. 11
Effect of the Change in Accounting Principle Applied Retroactively to the First Quarter of 2002 ---------------------------------------------------- Increase(Decrease) (millions) Reported net income...................... $116 ------------------------------------------------- Replacement of decommissioning expense... 26 Depreciation of asset retirement cost.... (2) Accretion of asset retirement cost....... (10) Income tax effect........................ (6) -------------------------------------------------- Total earnings effect.................... 8 ------------------------------------------------- Net income adjusted...................... $124 ================================================= Earnings per share of common stock (basic and diluted): Net income as previously reported $0.40 Adjustment for effect of change in accounting principle applied retroactively 0.02 ----- Net income adjusted $0.42 =====
In January 2003, the FASB issued an interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period after June 15, 2003 (FirstEnergy's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements, the sale of preferred securities and debt secured by bondable property, which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. FirstEnergy currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. In addition to the entities FirstEnergy is currently consolidating FirstEnergy believes that the PNBV Capital Trust, which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of OE's interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require consolidation. Ownership of the trust includes a three-percent equity interest by a nonaffiliated party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46 would change the characterization of the PNBV trust investment to a lease obligation bond investment. Also, consolidation of the outside minority interest would be required, which would increase assets and liabilities by $12.0 million. Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS133 for decisions made by the Derivative Implementation Group, as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for quarters which began prior to June 15, 2003, which continue to be applied based on their original effective dates. FirstEnergy is currently assessing the new standard and has not yet determined the impact on its financial statements. In June 2002, the EITF reached a partial consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Based on the EITF's partial consensus position, for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour (KWH) sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. Prior to its adoption for 2002 year end reporting, FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Comparative quarterly disclosures and the Consolidated Statements of Income for revenues and expenses have been reclassified for 2002 to conform with the revised presentation. In addition, the related KWH sales and purchases statistics described under Management's Discussion and Analysis of Results of Operations and Financial Condition were reclassified. The following table displays the impact of changing to a net presentation for FirstEnergy's energy trading operations. 12
Three Months Ended March 31, 2002 --------------------- 2002 Impact of Recording Energy Trading Net Revenues Expenses ------------------------------------------------------------------------ Revised Revised ------------------------------------------------------------------------ (in millions) Total before adjustment........................ $2,893 $2,404 Adjustment..................................... (40) (40) ------------------------------------------------------------------------- Total as reported.............................. $2,853 $2,364 ========================================================================= 6 - SEGMENT INFORMATION: FirstEnergy operates under two reportable segments: regulated services and competitive services. The aggregate "Other" segments do not individually meet the criteria to be considered a reportable segment. "Other" consists of interest expense related to the 2001 merger acquisition debt; the corporate support services operating segment and the international businesses acquired in the 2001 merger. The international business assets reflected in the 2002 "Other" assets amount included assets in the United Kingdom identified for divestiture (see Note 3 - Divestitures) which were sold in the second quarter of 2002. As those assets were in the process of being sold, their performance was not being reviewed by a chief operating decision maker and in accordance with SFAS 131, "Disclosures about Segments of an Enterprise and Related Information," did not qualify as an operating segment. The remaining assets and revenues for the corporate support services and the remaining international businesses were below the quantifiable threshold for operating segments for separate disclosure as "reportable segments." FirstEnergy's primary segment is its regulated services segment, which includes eight electric utility operating companies in Ohio, Pennsylvania and New Jersey that provide electric transmission and distribution services. Its other material business segment consists of the subsidiaries that operate unregulated energy and energy-related businesses. The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. It also provides generation services to regulated franchise customers who have not chosen 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. <TABLE> <CAPTION> Segment Financial Information ----------------------------- Regulated Competitive Reconciling Services Services Other(c) Adjustments Consolidated(c) --------- ----------- -------- ----------- --------------- (In millions) <S> <C> <C> <C> <C> <C> Three Months Ended: - ------------------- March 31, 2003 -------------- External revenues..................... $ 2,315 $ 866 $ 51 $ 12 (a) $ 3,244 Internal revenues..................... 264 560 124 (948) (b) -- Total revenues..................... 2,579 1,426 175 (936) 3,244 Depreciation and amortization......... 264 7 11 -- 282 Net interest charges.................. 122 11 105 (35) (b) 203 Income taxes.......................... 159 (31) (26) -- 102 Income before cumulative effect of accounting change.................. 227 (44) (44) -- 139 Net income............................ 328 (43) (44) -- 241 Total assets.......................... 29,649 2,449 1,421 -- 33,519 Property additions.................... 118 79 27 -- 224 March 31, 2002 -------------- External revenues..................... $ 1,995 $ 638 $ 214 $ 6 (a) $ 2,853 Internal revenues..................... 355 410 117 (882) (b) -- Total revenues..................... 2,350 1,048 331 (876) 2,853 Depreciation and amortization......... 244 7 12 -- 263 Net interest charges.................. 161 10 122 (14) (b) 279 Income taxes.......................... 162 (41) (27) -- 94 Net income (loss)..................... 198 (60) (22) -- 116 Total assets.......................... 29,147 2,706 6,288 (836) (b) 37,305 Property additions.................... 144 37 14 -- 195 <FN> Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting: (a) Principally fuel marketing revenues which are reflected as reductions to expenses for internal management reporting purposes. (b) Elimination of intersegment transactions. (c) Amounts revised in 2002 - See Note 1. </FN> </TABLE> 13
<TABLE> <CAPTION> FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended March 31, -------------------------------- 2003 2002 - ---------------------------------------------------------------------------------------------------------------- Revised (See Note 1) (In thousands, except per share amounts) <S> <C> <C> REVENUES: Electric utilities........................................................ $2,315,064 $2,053,976 Unregulated businesses.................................................... 929,408 799,302 ---------- ---------- Total revenues........................................................ 3,244,472 2,853,278 ---------- ---------- EXPENSES: Fuel and purchased power.................................................. 1,182,110 684,840 Purchased gas............................................................. 229,465 206,227 Other operating expenses.................................................. 929,239 1,037,751 Provision for depreciation and amortization............................... 281,662 262,828 General taxes............................................................. 178,282 171,988 ---------- ---------- Total expenses........................................................ 2,800,758 2,363,634 ---------- ---------- INCOME BEFORE INTEREST AND INCOME TAXES...................................... 443,714 489,644 ---------- ---------- NET INTEREST CHARGES: Interest expense.......................................................... 200,650 260,465 Capitalized interest...................................................... (9,152) (5,814) Subsidiaries' preferred stock dividends................................... 11,242 24,071 ---------- ---------- Net interest charges.................................................. 202,740 278,722 ---------- ---------- INCOME TAXES................................................................. 102,136 94,429 ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE......................... 138,838 116,493 Cumulative effect of accounting change (net of income taxes of $72,516,000) (Note 5)..................................................... 102,147 -- ---------- ---------- NET INCOME................................................................... $ 240,985 $ 116,493 ========== ========== BASIC EARNINGS PER SHARE OF COMMON STOCK: Income before cumulative effect of accounting change...................... $0.47 $0.40 Cumulative effect of accounting change (net of income taxes) (Note 5)..... 0.35 -- ------ ------ Net income................................................................ $0.82 $0.40 ===== ===== WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING.......................... 293,886 292,791 ======= ======= DILUTED EARNINGS PER SHARE OF COMMON STOCK: Income before cumulative effect of accounting change...................... $0.47 $0.40 Cumulative effect of accounting change (net of income taxes) (Note 5)..... 0.35 -- ------ ----- Net income................................................................ $0.82 $0.40 ===== ===== WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING........................ 294,877 294,344 ======= ======= DIVIDENDS DECLARED PER SHARE OF COMMON STOCK................................. $0.375 $0.375 ====== ====== <FN> The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. </FN> </TABLE> 14
<TABLE> <CAPTION> FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ----------- ----------- (In thousands) ASSETS ------ <S> <C> <C> CURRENT ASSETS: Cash and cash equivalents................................................. $ 290,036 $ 196,301 Receivables- Customers (less accumulated provisions of $55,945,000 and $52,514,000 respectively, for uncollectible accounts)............................. 1,149,390 1,153,486 Other (less accumulated provisions of $12,596,000 and $12,851,000, respectively, for uncollectible accounts)............................. 439,605 473,106 Materials and supplies, at average cost- Owned................................................................... 255,950 253,047 Under consignment....................................................... 159,268 174,028 Other..................................................................... 289,588 203,630 ----------- ----------- 2,583,837 2,453,598 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT: In service................................................................ 21,061,059 20,372,224 Less--Accumulated provision for depreciation.............................. 9,047,427 8,551,427 ----------- ----------- 12,013,632 11,820,797 Construction work in progress............................................. 963,422 859,016 ----------- ----------- 12,977,054 12,679,813 ----------- ----------- INVESTMENTS: Capital trust investments................................................. 1,042,143 1,079,435 Nuclear plant decommissioning trusts...................................... 1,060,994 1,049,560 Letter of credit collateralization........................................ 277,763 277,763 Other..................................................................... 899,551 918,874 ----------- ----------- 3,280,451 3,325,632 ----------- ----------- DEFERRED CHARGES: Regulatory assets......................................................... 7,949,286 8,323,001 Goodwill.................................................................. 5,855,494 5,896,292 Other..................................................................... 872,625 902,437 ----------- ----------- 14,677,405 15,121,730 ----------- ----------- $33,518,747 $33,580,773 =========== =========== </TABLE> 15
<TABLE> <CAPTION> FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ----------- ----------- (In thousands) <S> <C> <C> CAPITALIZATION AND LIABILITIES ------------------------------ CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... $ 1,630,227 $ 1,702,822 Short-term borrowings..................................................... 855,327 1,092,817 Accounts payable.......................................................... 885,651 918,268 Accrued taxes............................................................. 552,853 456,178 Other..................................................................... 987,004 1,000,415 ----------- ----------- 4,911,062 5,170,500 ----------- ----------- 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................................................... 6,119,286 6,120,341 Accumulated other comprehensive loss.................................... (657,411) (663,236) Retained earnings....................................................... 1,842,283 1,711,457 Unallocated employee stock ownership plan common stock - 3,613,860 and 3,966,269 shares, respectively (71,662) (78,277) ----------- ----------- Total common stockholders' equity................................... 7,262,260 7,120,049 Preferred stock of consolidated subsidiaries- Not subject to mandatory redemption..................................... 335,123 335,123 Subject to mandatory redemption......................................... 18,519 18,521 Subsidiary-obligated mandatorily redeemable preferred securities.......... 409,971 409,867 Long-term debt............................................................ 11,038,490 10,872,216 ----------- ----------- 19,064,363 18,755,776 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 2,405,174 2,367,997 Accumulated deferred investment tax credits............................... 230,046 235,758 Asset retirement obligation............................................... 1,126,786 -- Nuclear plant decommissioning costs....................................... -- 1,254,344 Power purchase contract loss liability.................................... 3,015,816 3,136,538 Retirement benefits....................................................... 1,643,501 1,564,930 Other..................................................................... 1,121,999 1,094,930 ----------- ----------- 9,543,322 9,654,497 ----------- ----------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ----------- ----------- $33,518,747 $33,580,773 =========== =========== <FN> The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these balance sheets. </FN> </TABLE> 16
<TABLE> <CAPTION> FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended March 31, ---------------------------- 2003 2002 - ------------------------------------------------------------------------------------------------------------------- Revised (See Note 1) (In thousands) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 240,985 $ 116,493 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization................................ 281,662 262,828 Nuclear fuel and lease amortization........................................ 14,918 20,965 Other amortization, net.................................................... (4,613) (3,537) Deferred costs recoverable as regulatory assets............................ (38,748) (70,134) Deferred income taxes, net................................................. 40,619 (20,534) Investment tax credits, net................................................ (6,259) (6,746) Cumulative effect of accounting change (Note 5)............................ (174,663) -- Receivables................................................................ 1,602 60,095 Materials and supplies..................................................... 11,413 18,163 Accounts payable........................................................... (18,915) (3,004) Accrued taxes.............................................................. 98,896 82,297 Accrued interest........................................................... 89,599 86,579 Deferred rents & sale/leaseback............................................ 3,558 71,438 Prepayments & other........................................................ (69,673) 109,551 Other...................................................................... (8,119) (260,370) --------- --------- Net cash provided from operating activities.............................. 462,262 464,084 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt............................................................. 297,696 105,031 Short-term borrowings, net................................................. -- 115,556 Redemptions and Repayments- Preferred stock............................................................ -- (185,299) Long-term debt............................................................. (200,866) (183,905) Short-term borrowings, net................................................. (237,490) -- Common stock dividend payments............................................... (110,159) (109,726) --------- --------- Net cash provided from (used for) financing activities................... (250,819) (258,343) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (224,419) (195,292) Avon cash and cash equivalents previously held for sale (Note 3)............. -- 411,822 Net assets held for sale..................................................... -- (61,565) Proceeds from nonutility generation trusts................................... 106,327 34,208 Proceeds from assets sale.................................................... 60,572 -- Cash investments............................................................. 24,715 (4,343) Other........................................................................ (84,903) 36,968 --------- --------- Net cash provided from (used for) investing activities................... (117,708) 221,798 --------- --------- Net increase in cash and cash equivalents....................................... 93,735 427,539 Cash and cash equivalents at beginning of period................................ 196,301 220,178 --------- --------- Cash and cash equivalents at end of period...................................... $ 290,036 $ 647,717 ========= ========= <FN> The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. </FN> </TABLE> 17
REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders and Board of Directors of FirstEnergy Corp.: We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of March 31, 2003, and the related consolidated statements of income and cash flows for the three-month periods ended March 31, 2003 and 2002. These interim 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 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. As discussed in Note 1 to the consolidated financial statements, the Company has revised the presentation of its Consolidated Statement of Income for the quarter ended March 31, 2002. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholders' equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for goodwill in 2002 as discussed in Note 2(E) to those consolidated financial statements and the Company's revised presentation of its Consolidated Statement of Income for the year ended December 31, 2002 as discussed in Note 2(L) to those consolidated financial statements) dated February 28, 2003, except as to Note 2(L) and Note 3, which are as of May 9, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003 18
FIRSTENERGY CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), the availability and cost of capital, our ability to accomplish or realize anticipated benefits from strategic initiatives and other similar factors. FirstEnergy Corp. is a registered public utility holding company that provides regulated and competitive energy services (see Results of Operations - Business Segments) domestically and internationally. The international operations were acquired as part of FirstEnergy's acquisition of GPU, Inc. in November 2001. GPU Capital, Inc. and its subsidiaries provide electric distribution services in foreign countries. GPU Power, Inc. and its subsidiaries develop, own and operate generation facilities in foreign countries. Sales are planned but not pending for the remaining international operations (see Capital Resources and Liquidity). Regulated electric distribution services are provided in Ohio by wholly owned subsidiaries (Ohio electric utilities) - Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), and The Toledo Edison Company (TE). Regulated services are provided in Pennsylvania through wholly owned subsidiaries (Pennsylvania electric utilities) - Metropolitan Edison Company (Met-Ed), Pennsylvania Electric Company (Penelec) and Pennsylvania Power Company (Penn) - a wholly owned subsidiary of OE. Jersey Central Power & Light Company (JCP&L) provides electric distribution services in New Jersey. Transmission services are provided in the franchise areas of the Ohio electric utilities and Penn by wholly owned subsidiary American Transmission Systems, Inc. (ATSI). Transmission services are provided by Met-Ed, Penelec and JCP&L in their respective franchise areas. The coordinated delivery of energy and energy-related products, including electricity, natural gas and energy management services, to customers in competitive markets is provided through a number of subsidiaries. Subsidiaries providing competitive services include FirstEnergy Solutions Corp. (FES), FirstEnergy Facilities Services Group, LLC (FSG), MARBEL Energy Corporation and MYR Group, Inc. Results of Operations - --------------------- Net income in the first quarter of 2003 was $241.0 million or $0.82 per share of common stock (basic and diluted), compared to $116.5 million or $0.40 per share of common stock (basic and diluted) in the first quarter of 2002. Net income in the first quarter of 2003 included an after-tax credit of $102.1 million resulting from the cumulative effect of an accounting change due to the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect of an accounting change was $138.8 million in the first three months of 2003, or $0.47 per share of common stock (basic and diluted). Results in the first quarter of 2003, before the accounting change, benefited from increased revenues due to cold weather, increased gas margins, and reduced financing costs. Partially offsetting these favorable factors were higher employee benefit expenses and incremental costs (which reduced basic and diluted earnings per share by $0.18) related to the extended outage at the Davis-Besse nuclear plant (see Davis-Besse Restoration). Reclassifications of Previously Reported Income Statement FirstEnergy recorded an increase to income during the three months ended March 31, 2002 of $31.7 million (net of income taxes of $13.6 million) relative to its decision to retain an interest in the Avon Energy Partners Holdings (Avon) business previously classified as held for sale - see Note 3. This amount represents the aggregate results of operations of Avon for the period this business was held for sale. It was previously reported on the Consolidated Statement of Income as the cumulative effect of a change in accounting. In April 2003, it was determined that this amount should instead have been classified in operations. As further discussed in Note 3, the decision to retain Avon was made in the first quarter of 2002 and Avon's results of operations for that quarter have been classified in their respective revenue and expense captions on the Consolidated Statement of Income. This change in classification had no effect on previously reported net income. The effects of this change on the Consolidated Statement of Income previously reported for the three months ended March 31, 2002 are shown in Note 1. In June 2002, the Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Based on the EITF's partial consensus position, for periods after July 15, 19
2002, mark-to-market revenues and expenses and their related kilowatt-hour sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Therefore, revenues and expenses for the first quarter of 2002 have been reclassified (see Implementation of Recent Accounting Standard). Revenues Total revenues increased $391.2 million in the first quarter of 2003, compared to the same period last year as a result of additional sales in FirstEnergy's regulated and competitive service segments. Electric and gas sales revenue increased due to colder than normal weather in the first quarter of 2003 compared to milder than normal weather in the first three months of 2002. Sources of changes in revenues during the first quarter of 2003 compared to the first quarter of 2002 are summarized in the following table:
Sources of Revenue Changes ------------------------------------------------------ Increase (Decrease) (In millions) Electric Utilities (Regulated Services): Retail electric sales.................. $ 108.2 Wholesale electric sales .............. 139.5 All other revenues..................... 13.4 --------------------------------------------------- Total Electric Utilities................. 261.1 --------------------------------------------------- Unregulated Businesses (Competitive Services): Retail electric sales.................. 66.7 Wholesale electric sales............... 233.8 Gas sales.............................. 43.9 FSG.................................... (42.4) Other.................................. (8.9) --------------------------------------------------- Total Unregulated Businesses............. 293.1 --------------------------------------------------- International............................ (162.3) Other.................................... (0.7) --------------------------------------------------- Net Revenue Increase..................... $ 391.2 =================================================== Electric Sales Retail sales by FirstEnergy's electric utility operating companies (EUOC) increased by $108.2 million in the first quarter of 2003 compared to the first quarter of 2002. Temperatures in the EUOC service areas ranged from 20% to 30% colder in the first quarter of 2003, compared to the same period last year, increasing residential and commercial heating loads. Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the same quarter of 2002 are summarized in the following table: Changes in Kilowatt-hour Sales ------------------------------------------------ Increase (Decrease) Electric Generation Sales: Retail - Regulated services.............. 2.1% Competitive services............ 130.2% Wholesale....................... 141.3% ------------------------------------------------- Total Electric Generation Sales..... 30.6% ================================================= EUOC Distribution Deliveries: Residential....................... 15.4% Commercial........................ 11.7% Industrial........................ 1.3% ------------------------------------------------- Total Distribution Deliveries....... 9.4% =================================================
Shopping by customers for alternative energy suppliers and the effect of a sluggish national economy in FirstEnergy's service areas combined to reduce regulated retail generation sales revenue by $4.7 million in the first quarter of 2003 from the same period in 2002, despite the colder weather in 2003. Sales of electric generation by alternative suppliers in Ohio, Pennsylvania and New Jersey in the first quarter of 2003 increased by 8.8, 4.4 and 0.8 percentage points, respectively, or 5.8 percentage points on a consolidated basis from the first quarter of 2002. 20
Revenues from distribution deliveries increased by $127.2 million or 11.2% in the first quarter of 2003 compared to the first quarter of 2002 largely due to the colder temperatures. Increased kilowatt-hour deliveries resulted from additional demand from all three customer segments: residential, commercial and industrial. The slower industrial growth continued to reflect sluggish economic conditions. Partially offsetting the increase in revenues from distribution deliveries were Ohio transition plan incentives provided to customers to promote customer shopping for alternative suppliers - $14.4 million of additional credits in the first quarter of 2003 compared to the same period in 2002. These reductions in revenue are deferred for future recovery under the Ohio transition plan and do not materially affect current period earnings. EUOC sales to wholesale customers increased by $139.5 million in the first quarter of 2003 from the same quarter last year. The increase occurred almost entirely at JCP&L and resulted from the auction of its entire basic generation service (BGS) responsibility to alternative suppliers. At the direction of the New Jersey Board of Public Utilities (NJBPU), JCP&L is selling its pre-existing sources of power supply, including energy provided by non-utility generation (NUG) contracts, into the wholesale market. Electric generation sales by FirstEnergy's competitive segment increased $300.5 million in the first quarter of 2003 from the first quarter of 2002, primarily from additional sales to the wholesale market ($233.8 million) as FES began supplying a portion of New Jersey's BGS requirements in September 2002. Retail sales by FirstEnergy's competitive services segment increased by $66.7 million from kilowatt-hour sales that were more than double the prior year's level. That increase resulted in part from retail customers switching to FES, under Ohio's electricity choice program. The higher kilowatt-hour sales in Ohio were partially offset by lower retail sales in markets outside of Ohio. FirstEnergy's regulated and unregulated subsidiaries record purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." This gross basis classification of revenues and costs may not be comparable to other energy companies that operate in regions that have not established ISOs and do not meet EITF 99-19 criteria. The aggregate purchase and sales transactions for the three months ended March 31, 2003 and 2002 are summarized as follows: Three Months Ended March 31, ---------------------- 2003 2002 - -------------------------------------------- (In millions) Sales.............. $336 $46 Purchases.......... 361 80 - ------------------------------------------- FirstEnergy's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from the PJM ISO from power sales (as reflected in the table above) during periods when it had additional available power capacity. Revenues also include sales by FirstEnergy of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when it required additional power to meet FirstEnergy's retail load requirements and, secondarily, to sell to the wholesale market. International revenues declined $162.3 million due to the sale of a 79.9% interest in Avon during the second quarter of 2002 and the subsequent application of equity accounting to FirstEnergy's remaining 20.1% interest. As a result, no revenues were recorded for FirstEnergy's equity interest in Avon in the first quarter of 2003. Nonelectric Sales Nonelectric sales revenues of the competitive services segment declined by $7.4 million in the first quarter of 2003 from the same period in 2002. Reduced revenues from FSG were substantially offset by higher natural gas sales revenues resulting from a weather-stimulated increase in prices in the first three months of 2003. The reduced revenues from FSG also reflected the sales in early 2003 of Colonial Mechanical and Webb Technologies, as well as continued declines associated with weak economic conditions. 21
Expenses Total expenses increased $437.1 million in the first quarter of 2003 from the same quarter of 2002. Sources of changes in expenses in the first quarter of 2003 from the first quarter of 2002 are summarized in the following table: Sources of Expense Changes - ----------------------------------------------------- Increase (Decrease) (In millions) Fuel and purchased power $ 497.3 Purchased gas 23.2 Other operating expenses (108.5) Depreciation and amortization 18.8 General taxes 6.3 - ----------------------------------------------------- Net Expense Increase $ 437.1 ===================================================== The net increase in expenses in the first quarter of 2003 compared to the first quarter of 2002 was primarily due to a $510.2 million increase in purchased power costs. The increase resulted from additional volumes to cover supply obligations assumed by FES for sales to the New Jersey market to provide BGS, and additional supplies required to replace Davis-Besse power during its extended outage (see Davis-Besse Restoration). The extended outage at the Davis-Besse nuclear plant produced a decline in nuclear generation of 16.7% in the first quarter of 2003, compared to the first quarter of 2002. Purchased gas costs increased by $23.2 million in the first quarter of 2003 compared to the same period of 2002 due to higher unit costs, partially offset by lower volumes purchased to meet reduced sales levels. Despite reduced quantities of gas sold, gross profit margins improved by $18.5 million during the first quarter of 2003, compared to the same period last year. Other operating expenses decreased $108.5 million in the first quarter of 2003 from the first quarter of 2002. The decrease primarily resulted from reduced business volume from domestic energy-related businesses which lowered other operating expenses by $66.1 million, reduced international expenses of $72.5 million (due to the sale of Avon) and the absence of one-time charges recorded in the first quarter of 2002 of $78.2 million. The reduced volume of energy-related business reflected the sale in early 2003 of the Colonial Mechanical and Webb Technologies businesses, as well as continued declines associated with weak economic conditions. Partially offsetting these lower expenses were $36.3 million of additional nuclear costs resulting from the Davis-Besse extended outage and $50.4 million in higher employee benefit costs. Charges for depreciation and amortization increased by $18.8 million in the first quarter of 2003 compared to the first quarter of 2002. The higher charges primarily resulted from three factors - increased amortization of the Ohio transition regulatory assets ($28.8 million), recognition of depreciation on four fossil plants ($9.6 million) which had been held pending sale in the first quarter of 2002, but were subsequently retained by FirstEnergy in the fourth quarter of 2002, and reduced tax related deferrals in 2003 ($7.9 million). Partially offsetting these increases in depreciation and amortization were higher shopping incentive deferrals in Ohio ($14.4 million) and lower charges resulting from the implementation of SFAS 143 ($11.6 million), including revised service life assumptions for generating plants ($8.0 million). Net Interest Charges Net interest charges decreased $76.0 million in the first quarter of 2003 compared to the same period of 2002. FirstEnergy's redemption and refinancing of its outstanding debt and preferred stock over the last twelve months, resulted in a $57.1 million reduction of financing costs. In addition, the sale of FirstEnergy's 79.9% interest in Avon eliminated $18.9 million of financing costs. Redemption and refinancing activities during the first quarter of 2003 totaled $122 million (excluding net reductions to various revolving bank facilities) and $563 million, respectively, and are expected to result in annualized savings of approximately $20 million. Partially offsetting these savings were $2.4 million of incremental interest costs associated with the issuance of $250 million of new senior notes. FirstEnergy also exchanged existing fixed-rate payments on outstanding debt (principal amount of $700 million as of March 31, 2003) for short-term variable rate payments through interest rate swap transactions (see Market Risk Information - Interest Rate Swap Agreements below). Net interest charges were reduced by $6.9 million in the first quarter of 2003, compared to the first quarter of 2002 as a result of these swaps. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 (see discussion further below) in the first quarter of 2003, FirstEnergy recorded an after-tax credit to net income of $102.1 million. FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $602 million were recorded 22
as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The asset retirement obligation (ARO) liability at the date of adoption was $1.109 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.232 billion, including unrealized gains on decommissioning trust funds of $12 million. FirstEnergy expects substantially all of its nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn to be recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for those companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the liabilities was a $174.6 million increase to income, or $102.1 million net of income taxes. Unrealized gains on decommissioning trust investments ($7 million net of tax) formerly included in the decommissioning liability balances as of December 31, 2002 were offset against Other Comprehensive Income (OCI) upon the adoption of SFAS 143 (see Note 5). Earnings Effect of SFAS 143 In June 2001, the FASB issued SFAS 143. The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead, if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. In the first quarter of 2003, application of SFAS 143 (excluding the cumulative adjustment recorded upon adoption -- See Note 5 ) resulted in the following changes to income and expense categories: Effect of SFAS 143 -- First Quarter 2003 ---------------------------------------- Increase (decrease) (millions) Other operating expense ----------------------- Cost of removal (previously included in depreciation).... $ 4.2 Depreciation ------------ Replacement of decommissioning expense................... (22.4) Depreciation of asset retirement cost.................... 1.9 Accretion of asset retirement liability.................. 9.9 Reclassification of cost of removal to expense .......... (3.9) ---------------------------------------------------------------------- Net impact to depreciation............................... (14.5) ---------------------------------------------------------------------- Other Income ------------ Earnings on trust balances............................... 2.5 --------------------------------------------------------------------- Income taxes............................................. 5.3 --------------------------------------------------------------------- Net income effect........................................ $7.5 =====================================================================
Postretirement Plans Sharp declines in equity markets since the second quarter of 2000 and a reduction in FirstEnergy's assumed discount rate for pensions and other postretirement obligations have combined to produce a significant increase in those costs. Also, increases in health care payments and a related increase in projected trend rates have led to higher health care costs. Combined, these employee benefit expenses increased $49.2 million in the first quarter of 2003 compared to the same period in 2002. The following table summarizes the net pension and other post-employment benefits (OPEB) expense (excluding amounts capitalized) for the three months ended March 31, 2003 and 2002.
Three Months Ended Postretirement Expense (Income) March 31, -------------------------------------------------------- 2003 2002 ---- ---- (In millions) Pension...................... $31.3 $(3.8) OPEB......................... 40.5 26.4 - -------------------------------------------------------- Total...................... $71.8 $22.6 ======================================================== 23
The pension and OPEB expense increases are included in various cost categories and have contributed to other cost increases discussed above. See "Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement expenses. 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 franchise customers who have not chosen an alternative generation supplier. The Ohio electric utilities and Penn obtain generation through a power supply agreement with the competitive services segment (see Outlook - Business Organization). The competitive services segment also supplies a substantial portion of the "provider of last resort" (PLR) requirements for Met-Ed and Penelec under contract. The competitive services segment includes all competitive energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation, trading and sourcing of commodity requirements, as well as other competitive energy services such as heating, ventilating and air-conditioning. Financial results discussed below include intersegment revenues. 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 $328.3 million in the first quarter of 2003, compared to $197.9 million in the first quarter of 2002. The factors contributing to the changes in net income are summarized in the following table:
Regulated Services -------------------------------------------------------- Increase (Decrease) (In millions) Revenues................................. $230.0 Expenses................................. 242.3 ------------------------------------------------------ Income Before Interest and Income Taxes.. (12.3) Net interest charges..................... (39.2) Income taxes............................. (2.5) ------------------------------------------------------- Income Before Cumulative Effect of a Change in Accounting..................... 29.4 Cumulative effect of a change in accounting 101.0 ------------------------------------------------------ Net Income............................... $130.4 ====================================================== Higher generation sales and distribution deliveries combined to increase external revenues by $247.7 million in the first quarter of 2003 compared to the same quarter of 2002. This increase was partially offset by a $31.1 million decline in revenues from lower sales to FES, resulting from the extended outage of the Davis-Besse nuclear plant, which decreased generation available for sale. The remaining change in sales resulted from an increase in energy-related revenues. The increase in expenses resulted principally from a $205.8 million increase in purchased power costs due to higher generation sales. Other operating expenses increased $14.9 million and depreciation and amortization expense was $19.9 million higher in the first quarter of 2003 compared to the same quarter last year. The increase in other operating expenses reflected additional employee benefit costs offset in part by the absence in the first quarter of 2003 of adjustments related to OE's low income housing investment and lower energy delivery costs. The increase in depreciation and amortization expense primarily resulted from three factors - increased amortization of the Ohio transition regulatory assets ($28.8 million), recognition of depreciation on four fossil plants ($9.6 million) which had been pending sale in the first quarter of 2002, but were subsequently retained by FirstEnergy in the fourth quarter of 2002 and the termination of tax related deferrals in February 2003 ($7.9 million). Partially offsetting these increases in depreciation and amortization were higher incentive deferrals in Ohio ($14.4 million) and lower charges resulting from the implementation of SFAS 143 ($11.6 million), including revised service life assumptions for generating plants ($8.0 million). Competitive Services Net losses decreased to $43.1 million in the first quarter of 2003, compared to $59.6 million in the first quarter of 2002. The factors contributing to the reduced loss are summarized in the following table: 24
Competitive Services ------------------------------------------------------- Increase (Decrease) (In millions) Revenues................................... $ 377.8 Expenses................................... 351.4 ------------------------------------------------------ Income Before Interest and Income Taxes.... 26.4 ------------------------------------------------------ Net interest charges....................... 1.0 Income taxes............................... 10.1 ------------------------------------------------------ Income Before Cumulative Effect of a Change in Accounting..................... 15.3 Cumulative effect of a change in accounting 1.2 ------------------------------------------------------ Net Income................................. $ 16.5 ======================================================
The increase in revenues in the first quarter of 2003, compared to the first quarter of 2002, includes the net effect of several factors. Revenues from the electric wholesale market increased $233.8 million in the first quarter of 2003 from the same period last year as kilowatt-hour sales more than doubled resulting principally from sales as an alternative supplier for a portion of New Jersey's BGS requirements. Retail kilowatt-hour sales revenues increased $66.7 million as a result of expanding the FES business in Ohio under Ohio's electricity choice program and higher weather stimulated sales to existing customers. Natural gas sales were $43.9 million higher due to higher prices resulting from colder weather in the first quarter of 2003, compared to the same period last year. Internal sales to the regulated services segment increased $90.3 million primarily reflecting sales to Met-Ed and Penelec in supplying a substantial portion of their PLR requirements in Pennsylvania. Energy-related services such as heating, ventilating and air-conditioning work reflected the divestiture in early 2003 of Colonial Mechanical and Webb Technologies, as well as continued declines associated with weak economic conditions. Revenues from energy-related services decreased $69.9 million in the first quarter of 2003 from the first quarter of 2002. Expenses increased $351.4 million in the first quarter of 2003 from the same period of 2002 primarily attributable to purchased power costs, which increased $405.8 million to source the higher kilowatt-hour sales to wholesale and retail customers. Gas costs also increased in the first quarter of 2003 by $23.2 million, reflecting higher unit costs during the colder than normal weather compared to the first quarter of 2002. Partially offsetting these factors were lower costs due to reduced business volume for domestic energy-related businesses of $61.1 million and other operating expenses which decreased $17.5 million. The decrease in other operating costs reflected the absence of $65.6 million of one-time charges in the first quarter of 2002, partially offset by higher nuclear production costs from the extended Davis-Besse outage and increased employee benefit costs (principally pension and health care). Capital Resources and Liquidity - ------------------------------- FirstEnergy's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing FirstEnergy's net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, FirstEnergy expects to meet its contractual obligations with cash from operations. Thereafter, FirstEnergy expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $1.5 billion of revolving credit facilities. In the first quarter of 2003, FirstEnergy received $137.0 million of cash dividends from its subsidiaries and paid $110.2 million in cash common stock dividends to its shareholders. There are no material restrictions on the issuance of cash dividends by FirstEnergy's subsidiaries. As of March 31, 2003, FirstEnergy had $290.0 million of cash and cash equivalents, compared with $196.3 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash flows provided from operating activities during the first quarter of 2003, compared with the first quarter of 2002 were as follows: 25
Operating Cash Flows 2003 2002 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 354 $ 334 Working capital and other............ 108 130 ------------------------------------------------------------- Total................................ $ 462 $ 464 ============================================================= (1)Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities decreased $2 million due to a $22 million increase in funds used for working capital that was offset in part by a $20 million increase in cash earnings. The change in funds used for working capital represents offsetting changes for receivables, sale and leaseback rent payments, prepayments and other. Cash Flows From Financing Activities The following table provides details regarding security issuances and redemptions during the first quarter of 2003: Securities Issued or Redeemed in the First Quarter 2003 -------------------------------------------------------------- (In millions) New Issues Senior Notes.............................. 250 Long-term revolver........................ 50 Other, primarily debt discount............ (2) ----- 298 Redemptions First mortgage bonds...................... 40 Pollution control notes................... 50 Secured notes............................. 108 Other, primarily redemption premiums...... 3 ---------------------------------------------------------- 201 Short-term Borrowings, Net Use of Cash......... 237 ----------------------------------------------------------
Net cash flows used for financing activities declined by $8 million in the first quarter of 2003 from the first quarter of 2002. The decrease in funds used for financing activities resulted from increased financing of $77 million that exceeded $69 million of additional redemptions and repayments during the first quarter of 2003 compared to the same period of 2002. FirstEnergy had approximately $855.3 million of short-term indebtedness as of March 31, 2003 compared to $1.093 billion at the end of 2002. Available borrowing capability included $356 million under the $1.5 billion revolving lines of credit and $76 million under bilateral bank facilities. As of March 31, 2003, OE, CEI, TE and Penn had the aggregate capability to issue $2.2 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds. JCP&L, Met-Ed and Penelec no longer issue FMB other than as collateral for senior notes, since their senior note indentures prohibit them (subject to certain exceptions) from issuing any debt which is senior to the senior notes. As of March 31, 2003, JCP&L, Met-Ed and Penelec had the aggregate capability to issue $443 million of additional senior notes based upon FMB collateral. Based upon applicable earnings coverage tests and their respective charters, OE, Penn, TE and JCP&L could issue a total of $4.5 billion of preferred stock. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock. On March 17, 2003, FirstEnergy filed a registration statement with the U.S. Securities and Exchange Commission covering securities in the aggregate amount of up to $2 billion. Although the Company does not have any current plans to issue securities, the shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, or share purchase contracts and related share purchase units. On April 21, 2003, OE completed a $325 million refinancing transaction that included two tranches -- $175 million of 4.00% five year notes and $150 million of 5.45% twelve year notes. The net proceeds will be used to redeem approximately $220 million of outstanding OE first mortgage bonds having a weighted average cost of 7.99%, with the remainder to be used to pay down short-term debt. 26
On May 1 and May 2, 2003, FirstEnergy executed two fixed-for-floating interest rate swap agreements with notional values of $50 million each on underlying senior notes with an average fixed interest rate of 4.73%. Cash Flows From Investing Activities Net cash flows used for investing activities totaled $118 million in the first quarter of 2003, compared to net cash flows of $222 million provided from investing activities for the same period of 2002. The $340 million change resulted from the absence of the Avon cash amount recognized in the first quarter of 2002 resulting from the reclassification from the "Assets Pending Sale" presentation to normal operations presentation (see Note 3), increased capital expenditures and other, offset in part by an increase in cash investments and proceeds from NUG trusts. The following table summarizes first quarter of 2003 investments by FirstEnergy's regulated services and competitive services segments: Summary of First Quarter 2003 Property Cash Used for Investing Activities Additions Investments Other Total ------------------------------------------------------------------------------ Sources (Uses) (in millions) Regulated Services................. $(118) $136 (1) $ (8) $ 10 Competitive Services............... (79) 63 (2) (71) (87) Other.............................. (27) (77) 3 (101) Eliminations....................... -- -- 60 60 ----------------------------------------------------------------------------- Total......................... $(224) $122 $(16) $(118) =============================================================================== (1) Includes $106 million proceeds from NUG trusts. (2) Includes $61 million proceeds from sale of assets. During the remaining three quarters of 2003, capital requirements for property additions and capital leases are expected to be approximately $578 million, including $36 million for nuclear fuel. FirstEnergy has additional requirements of approximately $378 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on its credit ratings. On April 11, 2003 Moody's Investors Service affirmed its existing ratings for FirstEnergy. Moody's noted that the ratings were based on the stable business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for the EUOC. Moody's noted that merger debt had put pressure on FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all levels within the company although those plans had been delayed by external events. Other Obligations - ----------------- Obligations not included on FirstEnergy's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant. As of March 31, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.5 billion. Also, CEI and TE continue to sell substantially all of their retail customer receivables, which provided $145 million of financing not included in the Consolidated Balance Sheet as of March 31, 2003. 27
Guarantees and Other Assurances - ------------------------------- As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and ratings contingent collateralization provisions. As of March 31, 2003, the maximum potential future payments under outstanding guarantees and other assurances totaled $960.2 million as summarized below: Maximum Guarantees and Other Assurances Exposure -------------------------------------------------------------- (In millions) FirstEnergy Guarantees of Subsidiaries: Energy and Energy-Related Contracts(1)...... $ 774.4 Financings (2)(3)........................... 98.3 - ------------------------------------------------------------- 872.7 Surety Bonds.................................. 25.8 Rating-Contingent Collateralization (4)....... 61.7 ---------------------------------------------------------- Total Guarantees and Other Assurances....... $ 960.2 ============================================================= (1) Issued for a one-year term, with a 10-day termination right by FirstEnergy. (2) Includes parental guarantees of subsidiary debt and lease financing including FirstEnergy's letters of credit supporting subsidiary debt. (3) Issued for various terms. (4) Estimated net liability under contracts subject to rating-contingent collateralization provisions. FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by FirstEnergy's other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with energy-related activities is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions. Various contracts include credit enhancements in the form of cash collateral, letters of credit or other security in the event of a reduction in credit rating. Requirements of these provisions vary and typically require more than one rating reduction to below investment grade by S&P or Moody's to trigger additional collateralization. Emdersa Abandonment - ------------------- On April 18, 2003, FirstEnergy divested its ownership of Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. Prior to the abandonment, FirstEnergy had recorded a foreign currency translation adjustment (CTA) loss of $90 million through its other comprehensive income (OCI) - a component of common stockholders' equity. The CTA reduced FirstEnergy's common stockholders' equity and did not affect its net income. As a result of the abandonment, FirstEnergy will recognize a one-time, non-cash charge of $63 million, or $0.21 per share of common stock in the second quarter of 2003. This charge is the result of realizing the CTA losses through its current period earnings ($90 million, or $0.30 per share), partially offset by the gain recognized from eliminating its investment in Emdersa ($27 million, or $0.09 per share). Since FirstEnergy had previously recorded $90 million of CTA adjustments in OCI, the net effect of the $63 million charge will be an increase in common stockholders' equity of $27 million. The $63 million charge does not include the anticipated income tax benefits related to the abandonment, which will be fully reserved during the second quarter. FirstEnergy anticipates tax benefits of approximately $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million of tax benefits would reduce goodwill recognized in connection with the acquisition of GPU. When 28
realized, the $129 million of tax benefits will represent positive cash flows for FirstEnergy and increase its common stockholders' equity by $50 million. Market Risk Information FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk FirstEnergy is exposed to market risk primarily due to fluctuations in electricity, natural gas and coal prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. Most of FirstEnergy's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2003 is summarized in the following table: <TABLE> <CAPTION> Increase (Decrease) in the Fair Value of Commodity Derivative Contracts Non-Hedge Hedge Total - ------------------------------------------------------------------------------------------------ (In millions) <S> <C> <C> <C> Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2003................... $53.8 $ 24.1 $ 77.9 New contract value when entered............................... -- -- -- Additions/Increase in value of existing contracts............. 17.2 29.1 46.3 Change in techniques/assumptions.............................. -- -- -- Settled contracts............................................. (4.6) (10.3) (14.9) - ------------------------------------------------------------------------------------------------- Outstanding net asset as of March 31, 2003 (1)................ 66.4 42.9 109.3 - ------------------------------------------------------------------------------------------------- Non-commodity net assets as of March 31, 2003: Interest Rate Swaps (2)....................................... -- 24.0 24.0 - ------------------------------------------------------------------------------------------------- Net Assets - Derivatives Contracts as of March 31, 2003 (3)... $66.4 $ 66.9 $133.3 ================================================================================================= Impact of Changes in Commodity Derivative Contracts (4) Income Statement Effects (Pre-Tax)............................ $(3.5) $ -- $ (3.5) Balance Sheet Effects: Other Comprehensive Income (Pre-Tax).......................... $ -- $ 18.8 $ 18.8 Regulatory Liability.......................................... $16.1 $ -- $ 16.1 <FN> (1) Includes $50.3 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Interest rate swaps are treated as fair value hedges. Changes in derivative values are offset by changes in the hedged debts' premium or discount. (3) Excludes $26.7 million of derivative contract fair value decrease, as of March 31, 2003, representing FirstEnergy's 50% share of Great Lakes Energy Partners, LLC. (4) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. </FN> </TABLE> Derivatives included on the Consolidated Balance Sheet as of March 31, 2003:
Non-Hedge Hedge Total - --------------------------------------------------------------------- (In millions) Current- Other Assets...................... $ 30.1 $31.1 $ 61.2 Other Liabilities................. (32.4) (2.3) (34.7) Non-Current- Other Deferred Charges............ 70.4 38.9 109.3 Other Deferred Credits............ (1.7) (0.8) (2.5) - ---------------------------------------------------------------------- Net assets........................ $ 66.4 $66.9 $133.3 ====================================================================== 29
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 uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table:
<TABLE> <CAPTION> Source of Information - - Fair Value by Contract Year 2003(1) 2004 2005 2006 Thereafter Total - -------------------------------------------------------------------------------------------------------------- (In millions) <S> <C> <C> <C> <C> <C> <C> Prices actively quoted(2)............. $12.6 $ 2.6 $ -- $ -- $ -- $15.2 Other external sources(3)............. 26.7 15.8 9.3 -- -- 51.8 Prices based on models................ -- -- -- 6.3 36.0 42.3 - -------------------------------------------------------------------------------------------------------------- Total(4)........................... $39.3 $18.4 $9.3 $6.3 $36.0 $109.3 ============================================================================================================== <FN> (1) For the last three quarters of 2003. (2) Exchange traded. (3) Broker quote sheets. (4) Includes $50.3 million from an embedded option that is offset by a regulatory liability and does not affect earnings. </FN> </TABLE> FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) 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 (assets, liabilities and equity) or cash flows as of March 31, 2003. Based on derivative contracts held as of March 31, 2003, an adverse 10% change in commodity prices would decrease net income by approximately $4.7 for the next twelve months. Interest Rate Swap Agreements During the first quarter of 2003, FirstEnergy entered into fixed-to-floating interest rate swap agreements, as part of its ongoing efforts to manage the interest rate risk of its liability portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, fixed interest rates and interest payment dates match those of the underlying obligations. The swap agreements consummated in the first quarter of 2003 are based on a notional principal amount of $200 million. Throughout the second half of 2002 and the first quarter of 2003, FirstEnergy utilized fixed-to-floating interest rate swap agreements to increase the variable-rate component of its debt portfolio. As of March 31, 2003, the debt underlying FirstEnergy's $700 million notional amount of outstanding fixed-for-floating interest rate swaps had a weighted average fixed interest rate of 7.10%, which the swaps have effectively converted to a current weighted average variable interest rate of 3.09%. GPU Power (through a subsidiary) used existing dollar-denominated interest rate swap agreements in the first quarter of 2003. The GPU Power agreements convert variable-rate debt to fixed-rate debt to manage the risk of increases in variable interest rates. GPU Power's swaps had a weighted average fixed interest rate of 6.68% as of March 31, 2003 and December 31, 2002. The following summarizes the principal characteristics of the swap agreements: Interest Rate Swaps <TABLE> <CAPTION> March 31, 2003 December 31, 2002 ----------------------------- ------------------------------- Notional Maturity Fair Notional Maturity Fair Denomination Amount Date Value Amount Date Value -------------------------------------------------------------------------------------------- (Dollars in millions) <S> <C> <C> <C> <C> <C> <C> Fixed to Floating Rate (Fair value hedges) $200 2006 $ 2.4 350 2023 14.5 $444 2023 $15.5 150 2025 7.9 150 2025 5.9 Floating to Fixed Rate (Cash flow hedges) $ 13 2005 $(0.8) $ 16 2005 $(0.9) - ------------------------------------------------------------------------------------------------ </TABLE> 30
Equity Price Risk Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $528 million and $532 million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $53 million reduction in fair value as of March 31, 2003. Outlook - ------- FirstEnergy continues to pursue its goal of being the leading regional supplier of energy and related services in the northeastern quadrant of the United States, where it sees the best opportunities for growth. Its fundamental business strategy remains stable and unchanged. While FirstEnergy continues to build toward a strong regional presence, key elements for its strategy are in place and management's focus continues to be on execution. FirstEnergy intends to provide competitively priced, high-quality products and value-added services - energy sales and services, energy delivery, power supply and supplemental services related to its core business. As FirstEnergy's industry changes to a more competitive environment, FirstEnergy has taken and expects to take actions designed to create a larger, stronger regional enterprise that will be positioned to compete in the changing energy marketplace. FirstEnergy's current focus includes: 1) returning Davis-Besse to safe and reliable operation; 2) optimizing FirstEnergy's generation portfolio; 3) effectively managing commodity supplies and risks; 4) reducing FirstEnergy's cost structure; 5) enhancing its credit profile and financial flexibility; and 6) achieving earnings growth targets. Business Organization FirstEnergy's business is managed as two distinct operating segments - - a competitive services segment and a regulated services segment. FES provides competitive retail energy services while the EUOC provide regulated transmission and distribution services. FirstEnergy Generation Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and operates those plants. FirstEnergy expects the transfer of ownership of EUOC non-nuclear generating assets to FGCO will be substantially completed by the end of the market development period in 2005. All of the EUOC power supply requirements for the Ohio Companies and Penn are provided by FES to satisfy their PLR obligations, as well as grandfathered wholesale contracts. State Regulatory Matters In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in the EUOC's respective state regulatory plans. However, despite these similarities, the specific approach taken by each state and for each of the EUOCs varies. Those provisions include: o allowing the EUOC's electric customers to select their generation suppliers; o establishing PLR obligations to non-shopping customers in the EUOC's service areas; o allowing recovery of potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; o itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; o deregulating the EUOC's electric generation businesses; and o continuing regulation of the EUOC's transmission and distribution systems. Regulatory assets are costs that the respective regulatory agencies have authorized for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of the regulatory assets are expected to continue to be recovered under the provisions of the respective transition and regulatory plans as discussed below. Regulatory assets declined $373.7 million to $7.9 billion as of March 31, 2003 from the balance as of December 31, 2002, with approximately one-half of the decrease related to the adoption of SFAS 143 by JCP&L, Met-Ed, Penelec and Penn. The regulatory assets of the individual companies are as follows: 31
Regulatory Assets as of -------------------------------------------------- March 31, December 31, Company 2003 2002 -------------------------------------------------- (In millions) OE.............. $1,775.7 $1,855.9 CEI............. 943.3 939.8 TE.............. 387.1 392.6 Penn............ 77.8 156.9 JCP&L........... 3,094.8 3199.0 Met-Ed.......... 1,126.9 1,179.1 Penelec......... 543.7 599.7 -------------------------------------------------- Total........... $7,949.3 $8,323.0 ================================================== Ohio FirstEnergy's transition plan (which FirstEnergy filed on behalf of its Ohio electric utilities) 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. In February 2003, the Ohio electric utilities were authorized increases in revenues aggregating approximately $50 million (OE - $41 million, CEI - $4 million and TE - - $5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation. 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 periods. New Jersey Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L submitted two rate filings with the New Jersey Board of Public Utilities (NJBPU) in August 2002. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current market transition charge and societal benefits charge (SBC) rates; one proposed method of recovery of these costs is the securitization of the deferred balance. Hearings began in February 2003. On March 18, 2003, a report prepared by independent auditors addressing costs deferred by JCP&L from August 1, 1999 through July 31, 2002, was transmitted to the Office of Administrative Law, where JCP&L's rate case is being heard. While the auditors concluded that JCP&L's energy procurement strategy and process was reasonable and prudent, they identified potential disallowances approximating $17 million. The report subjected $436 million of deferred costs to a retrospective prudence review during a period of extreme price uncertainty and volatility in the energy markets. Although JCP&L disagrees with the potential disallowances, it is pleased with the report's major conclusions and overall tone. Hearings concluded on April 28, 2003, and initial briefs were filed on May 7, 2003. The JCP&L brief supports its two rate filings requesting an aggregate rate increase of approximately $122 million in base electric rates and the recovery of deferred costs based on the securitization methodology discussed above. If the securitization methodology is not allowed, then JCP&L has requested deferred cost recovery over a four-year period with a return on the unamortized deferred cost balance. This alternative would increase the overall rate request to approximately $246 million. JCP&L strongly disagrees with many of the positions taken by NJBPU Staff. The Staff's position would result in a $119 million estimated annual earnings decrease related to the electricity delivery charge. In addition, the Staff recommended disallowing approximately $153 million of deferred energy costs which would result in a one-time pre-tax charge against earnings of $153 million (or $0.31 per share of common stock). JCP&L will respond to the Staff's position in its Reply Brief which is due on May 21, 2003. The Administrative Law Judge's recommended decision is due by the end of June 2003 and the NJBPU's subsequent decision is due in July 2003. In 1997, the NJBPU authorized JCP&L to recover from customers, subject to possible refund, $135 million of costs incurred in connection with a 1996 buyout of a power purchase agreement. JCP&L has recovered the full $135 million; the NJBPU has established a procedural schedule to take further evidence with respect to the buyout to enable it to make a final prudence determination contemporaneously with the resolution of the pending rate case. In December 2001, the NJBPU authorized the auctioning of BGS for the period from August 1, 2002 through July 31, 2003 to meet the electricity demands of all customers who have not selected an alternative supplier. The results of the February 2002 auction, with the NJBPU's approval, removed JCP&L's BGS obligation of 5,100 megawatts for the 32
period August 1, 2002 through July 31, 2003. In February 2003, the auctioning of BGS for the period beginning August 1, 2003 took place. The auction covered a fixed price bid (applicable to all residential and smaller commercial and industrial customers) and an hourly price bid (applicable to all large industrial customers) process. JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsets to its deferred energy cost balances. Pennsylvania Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to FES through a wholesale power sale which expires in December 2003 and may be extended for each successive calendar year. Under the terms of the wholesale agreement, FES assumed the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at or below the shopping credit for their uncommitted PLR energy costs during the term of the agreement to FES. FES has hedged most of Met-Ed's and Penelec's unfilled on-peak PLR obligation through 2004 and a portion of 2005. Met-Ed and Penelec will continue to defer those cost differences between NUG contract rates and the rates reflected in their capped generation rates. On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the Commonwealth Court's decision which effectively affirmed the PPUC's order approving the merger between FirstEnergy and GPU, let stand the Commonwealth Court's denial of PLR rate relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. On April 2, 2003, the PPUC remanded the merger savings issue to the Office of Administrative Law for hearings and directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court's order on the Settlement Stipulation by May 2, 2003. Because FirstEnergy had already reserved for the deferred energy costs and FES has largely hedged the anticipated PLR energy supply requirements for Met-Ed and Penelec through 2005, FirstEnergy, Met-Ed and Penelec believe that the disallowance of competitive transition charge recovery of PLR costs above Met-Ed's and Penelec's capped generation rates will not have a future adverse financial impact during that period. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FirstEnergy is also accelerating maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy discussed plans to test the bottom of the reactor for leaks and to install a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FirstEnergy anticipates that the unit will be ready for restart in the first half of the summer of 2003. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed FirstEnergy's plans to reduce post-merger debt levels FirstEnergy believes such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). Total incremental expenses associated with the extended Davis-Besse outage in the first quarter of 2003 totaled $88.6 million, including $36.3 million for maintenance work and $52.3 million for fuel and purchased power. It is anticipated that an additional $13.7 million in maintenance costs will be expended over the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month in the non-summer months and $20-25 million per month during the summer. FirstEnergy has hedged the on-peak replacement energy supply for Davis-Besse through the summer of 2003 and has completed some hedging for the balance of 2003 as well based on a probabilistic assessment of the unit's expected start-up date. 33
Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $159 million, which is included in the construction forecast provided under "Capital Expenditures" for 2003 through 2007. The Companies are required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies believe they are in compliance with the current SO2 and nitrogen 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 SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals for the D.C. Circuit found constitutional and other defects in the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating ultra-fine particulates but found defects in the new NAAQS rules for ozone and decided that the EPA must revise those rules. The future cost of compliance with these regulations may be substantial and will depend if and how they are ultimately implemented by the states in which the Companies operate affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio for which hearings began in February 2003. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of these proceedings, FirstEnergy believes the Sammis Plant is in full compliance with the Clean Air Act and the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. Several EUOC have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L 34
through the SBC. The Companies have total accrued liabilities aggregating approximately $53.9 million as of March 31, 2003. The effects of compliance on the EUOC with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Implementation of Recent Accounting Standard - -------------------------------------------- In June 2002, the EITF reached a partial consensus on Issue No. 02-03. Based on the EITF's partial consensus position, for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Comparative quarterly disclosures and the Consolidated Statements of Income for revenues and expenses have been reclassified for 2002 to conform with the revised presentation (see Note 5). In addition, the related kilowatt-hour sales and purchases statistics described above under Results of Operations were reclassified (1.3 billion kilowatt-hour in the first quarter of 2002). The following table displays the impact of changing to a net presentation for FirstEnergy's energy trading operations. Impact of Recording Energy Trading Net on the Previously Reported First Quarter of 2002 Revenues Expenses - ----------------------------------------------------------------------------- (in millions) Total before adjustment.............................. $2,893 $2,404 Adjustment........................................... (40) (40) - ------------------------------------------------------------------------------- Total as reported.................................... $2,853 $2,364 ============================================================================== 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 purchase price allocations for the GPU acquisition were finalized in the fourth quarter of 2002. 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 - $7.9 billion as of March 31, 2003. 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 35
transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. FirstEnergy continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, FirstEnergy enters into significant commodity contracts, as well as interest rate and currency swaps, which increase the impact of derivative accounting judgments. Revenue Recognition FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used at the end of 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in the first quarter of 2002 were computed assuming a 10.25% rate of return on plan assets. Beginning in the first quarter of 2003, the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the 36
equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," FirstEnergy periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, FirstEnergy recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur FirstEnergy would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. FirstEnergy's annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill -- fair value was higher than carrying value for each of its reporting units. The forecasts used in FirstEnergy's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on FirstEnergy's future evaluations of goodwill. As of March 31, 2003, FirstEnergy had $5.9 billion of goodwill that primarily relates to its regulated services segment. Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period after June 15, 2003 (FirstEnergy's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements, the sale of preferred securities and debt secured by bondable property, which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. FirstEnergy currently consolidates the majority of these entities and believe it will continue to consolidate following the adoption of FIN 46. In addition to the entities FirstEnergy is currently consolidating FirstEnergy believes that the PNBV Capital Trust, which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of OE's interest in the Perry Nuclear Plant and Beaver Valley Unit 2, would require consolidation. Ownership of the trust includes a three-percent equity interest by a nonaffiliated party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46 would change the characterization of the PNBV trust investment to a lease obligation bond investment. Also, consolidation of the outside minority interest would be required, which would increase assets and liabilities by $12.0 million. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS133 for decisions made by the Derivative Implementation Group, as well as 37
issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for quarters which began prior to June 15, 2003, which continue to be applied based on their original effective dates. FirstEnergy is currently assessing the new standard and has not yet determined the impact on its financial statements. 38
<TABLE> <CAPTION> OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended March 31, -------------------------- 2003 2002 -------- -------- (In thousands) <S> <C> <C> OPERATING REVENUES.............................................................. $742,743 $707,799 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 12,850 14,290 Purchased power.............................................................. 243,828 241,479 Nuclear operating costs...................................................... 125,368 95,234 Other operating costs........................................................ 94,113 79,611 -------- -------- Total operation and maintenance expenses................................... 476,159 430,614 Provision for depreciation and amortization.................................. 105,385 92,130 General taxes................................................................ 48,256 45,376 Income taxes................................................................. 43,254 42,615 -------- -------- Total operating expenses and taxes......................................... 673,054 610,735 -------- -------- OPERATING INCOME................................................................ 69,689 97,064 OTHER INCOME.................................................................... 14,031 512 -------- -------- INCOME BEFORE NET INTEREST CHARGES.............................................. 83,720 97,576 -------- -------- NET INTEREST CHARGES: Interest on long-term debt................................................... 24,488 33,073 Allowance for borrowed funds used during construction and capitalized interest (1,380) (621) Other interest expense....................................................... 2,478 5,147 Subsidiaries' preferred stock dividend requirements.......................... 912 3,626 -------- -------- Net interest charges....................................................... 26,498 41,225 -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 57,222 56,351 Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 5) 31,720 -- -------- -------- NET INCOME...................................................................... 88,942 56,351 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 659 2,596 -------- -------- EARNINGS ON COMMON STOCK........................................................ $ 88,283 $ 53,755 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements. </FN> </TABLE> 39
<TABLE> <CAPTION> OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ---------- ---------- (In thousands) <S> <C> <C> ASSETS ------ UTILITY PLANT: In service................................................................. $5,139,199 $4,989,056 Less--Accumulated provision for depreciation............................... 2,573,462 2,552,007 ---------- ---------- 2,565,737 2,437,049 ---------- ---------- Construction work in progress- Electric plant........................................................... 145,785 122,741 Nuclear fuel............................................................. 47,974 23,481 ---------- ---------- 193,759 146,222 ---------- ---------- 2,759,496 2,583,271 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: PNBV Capital Trust......................................................... 401,972 402,565 Letter of credit collateralization......................................... 277,763 277,763 Nuclear plant decommissioning trusts....................................... 296,298 293,190 Long-term notes receivable from associated companies....................... 503,510 503,827 Other...................................................................... 70,708 74,220 ---------- ---------- 1,550,251 1,551,565 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents.................................................. 14,320 20,512 Receivables- Customers (less accumulated provisions of $5,708,000 and $5,240,000, respectively for uncollectible accounts)................... 296,218 296,548 Associated companies..................................................... 619,084 592,218 Other (less accumulated provisions of $1,000,000 for uncollectible accounts at both dates)................................................ 33,430 33,557 Notes receivable from associated companies................................. 264,736 437,669 Materials and supplies, at average cost- Owned.................................................................... 58,564 58,022 Under consignment........................................................ 20,509 19,753 Prepayments and other...................................................... 26,697 11,804 ---------- ---------- 1,333,558 1,470,083 ---------- ---------- DEFERRED CHARGES: Regulatory assets.......................................................... 1,853,439 2,012,754 Property taxes............................................................. 59,035 59,035 Unamortized sale and leaseback costs....................................... 72,294 72,294 Other...................................................................... 51,800 51,739 ---------- ---------- 2,036,568 2,195,822 ---------- --------- $7,679,873 $7,800,741 ========== ========== </TABLE> 40
<TABLE> <CAPTION> OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ---------- ------------ (In thousands) <S> <C> <C> 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 Accumulated other comprehensive loss..................................... (62,548) (65,713) Retained earnings........................................................ 882,628 807,345 ---------- ---------- Total common stockholder's equity.................................... 2,918,809 2,840,361 Preferred stock not subject to mandatory redemption........................ 60,965 60,965 Preferred stock of consolidated subsidiary- Not subject to mandatory redemption...................................... 39,105 39,105 Subject to mandatory redemption.......................................... 13,500 13,500 Long-term debt............................................................. 1,238,877 1,219,347 ---------- ---------- 4,271,256 4,173,278 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock....................... 526,475 563,267 Short-term borrowings- Associated companies..................................................... 187 225,345 Other.................................................................... 175,197 182,317 Accounts payable- Associated companies..................................................... 173,086 145,981 Other.................................................................... 5,380 18,015 Accrued taxes.............................................................. 472,254 467,776 Accrued interest........................................................... 30,646 28,209 Other...................................................................... 100,683 73,882 ---------- ---------- 1,483,908 1,704,792 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes.......................................... 1,010,863 1,016,680 Accumulated deferred investment tax credits................................ 83,432 86,465 Asset retirement obligation................................................ 302,524 -- Nuclear plant decommissioning costs........................................ -- 292,353 Retirement benefits........................................................ 250,211 247,531 Other...................................................................... 277,679 279,642 ---------- ---------- 1,924,709 1,922,671 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)............................ ---------- ---------- $7,679,873 $7,800,741 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets. </FN> </TABLE> 41
<TABLE> <CAPTION> OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended March 31, 2003 2002 --------- --------- (In thousands) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 88,942 $ 56,351 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization................................ 105,385 92,130 Nuclear fuel and lease amortization........................................ 7,106 11,402 Deferred income taxes, net................................................. 8,683 (13,170) Investment tax credits, net................................................ (3,580) (3,773) Cumulative effect of accounting change (Note 5)............................ (54,109) -- Receivables................................................................ (26,409) 64,148 Materials and supplies..................................................... (1,298) (1,642) Accounts payable........................................................... 14,470 (18,295) Accrued taxes.............................................................. 4,478 56,884 Accrued interest........................................................... 2,437 6,237 Deferred rents & sale/leaseback............................................ 31,683 31,683 Prepayments & other........................................................ (14,893) 16,095 Other...................................................................... (9,378) (30,539) --------- --------- Net cash provided from operating activities.............................. 153,517 267,511 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt............................................................. -- 104,985 Short-term borrowings, net................................................. -- 40,306 Redemptions and Repayments- Long-term debt............................................................. (19,493) (89,547) Short-term borrowings, net................................................. (232,278) -- Dividend Payments Common stock............................................................... (13,000) (101,200) Preferred stock............................................................ (659) (2,597) --------- --------- Net cash provided from (used for) financing activities................... (265,430) (48,053) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (68,367) (30,344) Notes receivable from associated companies, net.............................. 173,250 (138,181) Other........................................................................ 838 1,972 --------- --------- Net cash provided from (used for) investing activities................... 105,721 (166,553) --------- --------- Net Increase (decrease) in cash and cash equivalents............................ (6,192) 52,905 Cash and cash equivalents at beginning of period................................ 20,512 4,588 --------- --------- Cash and cash equivalents at end of period...................................... $ 14,320 $ 57,493 ========= ========= <FN> The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements. </FN> </TABLE> 42
REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Ohio Edison Company: We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of March 31, 2003, and the related consolidated statements of income and cash flows for the three-month periods ended March 31, 2003 and 2002. These interim 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 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. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003 43
OHIO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. 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 - --------------------- Earnings on common stock in the first quarter of 2003 increased to $88.3 million from $53.8 million in the first quarter of 2002. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $31.7 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $57.2 million in the first three months of 2003, compared to $56.4 million for the same period of 2002. Improved results in the first quarter of 2003 reflect higher revenues due to colder weather, increased sales to FES and reduced financing costs, compared with the first quarter of 2002, as well as the absence of adjustments reflected in the first quarter of 2002 for OE's low income housing investments. Substantially offsetting these improvements were higher operating expenses -- primarily nuclear operating costs, employee benefit costs and depreciation and amortization. Operating revenues increased by $34.9 million or 4.9% in the first quarter of 2003 compared with the same period in 2002. The higher revenues resulted from increased distribution deliveries to residential and commercial customers due to colder temperatures and additional sales revenues to FES, which were partially offset by lower generation kilowatt-hour sales to retail customers. Kilowatt-hour sales to retail customers declined by 1.4% in the first quarter of 2003 from the same quarter of 2002, which reduced generation sales revenue by $13.6 million. Electric generation services provided by alternative suppliers as a percent of total sales delivered in OE's franchise area increased to 24.0% in the first quarter of 2003 from 17.1% in the first quarter of 2002. Distribution deliveries increased 7.6% in the first quarter of 2003 compared with the corresponding quarter of 2002, with increases in all customer sectors (residential, commercial and industrial). This increased revenues from electricity throughput by $37.6 million in the first quarter of 2003 from the same quarter of the prior year. Approximately 70% of the increase reflected higher volumes with the remainder due to higher unit prices. Distribution deliveries benefited from substantially higher residential and commercial demand, due in large part to colder temperatures, that was moderated by the continued effect of a sluggish economy and its impact on demand by industrial customers in OE's franchise area. Partially offsetting the increase in revenues from distribution deliveries were Ohio transition plan incentives provided to customers to promote customer shopping for alternative suppliers -- $6.3 million of additional credits in the first quarter of 2003 from the same period last year. These reductions in revenues are deferred for future recovery under OE's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers increased by $17.3 million (primarily to FES) in the first quarter of 2003 compared to the same quarter of 2002, due to higher market prices. Increased wholesale revenues occurred despite a reduction in kilowatt-hour sales in the first quarter of 2003 from the same quarter last year, due a 9.9% reduction in available nuclear generation from Beaver Valley Unit 1 as a result of its refueling outage that began on March 8, 2003. Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the same quarter of 2002 are summarized in the following table: 44
Changes in Kilowatt-Hour Sales --------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. (1.4)% Wholesale............................... (7.1)% --------------------------------------------------- Total Electric Generation Sales........... (4.0)% =================================================== Distribution Deliveries: Residential............................. 12.2% Commercial.............................. 8.7% Industrial.............................. 2.1% --------------------------------------------------- Total Distribution Deliveries............. 7.6% =================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $62.3 million in the first quarter of 2003 from the first quarter of 2002. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes ------------------------------------------------------------------ Increase (Decrease) (In millions) Fuel............................................. $ (1.4) Purchased power costs............................ 2.3 Nuclear operating costs.......................... 30.1 Other operating costs............................ 14.5 -------------------------------------------------------------- Total operation and maintenance expenses....... 45.5 Provision for depreciation and amortization...... 13.3 General taxes.................................... 2.9 Income taxes..................................... 0.6 -------------------------------------------------------------- Total operating expenses and taxes............. $62.3 ============================================================== Lower fuel costs in the first quarter of 2003, compared with the same quarter of 2002, resulted from reduced nuclear generation. The increased purchased power costs reflected additional kilowatt-hour purchases offset in part by lower unit costs. Higher nuclear operating costs occurred in large part due to the refueling outage at Beaver Valley Unit 1 (100% ownership) in the first quarter of 2003 compared with refueling outage costs at Beaver Valley Unit 2 (55.6% ownership) in the first quarter of 2002. The increase in other operating costs reflects higher employee benefit costs and increased uncollectible customer accounts. Charges for depreciation and amortization increased by $13.3 million in the first quarter of 2003 compared to the first quarter of 2002 primarily from two factors - increased amortization of the Ohio transition regulatory assets ($19.9 million) and reduced transition plan tax-related deferrals ($6.3 million) in 2003. Partially offsetting these increases were higher shopping incentive deferrals ($6.6 million) and lower charges resulting from the implementation of SFAS 143 ($4.7 million), including revised service life assumptions for generating plants ($1.0 million). General taxes increased in the first quarter of 2003 from the same quarter of last year principally due to higher kilowatt-hour taxes in Ohio as the result of increased kilowatt-hour deliveries. Other Income Other income increased by $13.5 million in the first quarter of 2003 from the same period last year, primarily due to the absence in the first quarter of 2003 of adjustments recorded in the first quarter of 2002 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 first quarter of 2003 from the same period last year, reflecting redemptions and refinancings since the first quarter of 2002. OE's net debt redemptions totaled $13.0 million during the first quarter of 2003, which will result in annualized savings of $1.1 million. 45
Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, OE recorded an after-tax credit to net income of $31.7 million. OE identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $133.5 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $25.2 million. The asset retirement obligation (ARO) liability at the date of adoption was $297.6 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, OE had recorded decommissioning liabilities of $292.4 million, including unrealized gains on the decommissioning trust funds of $10.6 million. Penn expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, OE recognized a regulatory liability of $10.6 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for Penn. The remaining cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $54.1 million increase to income, or $31.7 million net of income taxes. Unrealized gains on decommissioning trust investments ($6.2 million net of tax) formerly included in the decommissioning liability balances as of December 31, 2002 were offset against OCI upon the adoption of SFAS 143 (see Note 5). Capital Resources and Liquidity - ------------------------------- OE's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, OE expects to meet its contractual obligations with cash from operations. Thereafter, OE expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2003, OE had $14.3 million of cash and cash equivalents, compared with $20.5 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash flows provided by operating activities during the first quarter of 2003, compared with the corresponding period in 2002 were as follows: Operating Cash Flows 2003 2002 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $153 $143 Working capital and other............ 1 125 ------------------------------------------------------------- Total................................ $154 $268 ============================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash from operating activities decreased $114 million due to a $124 million increase in funds used for working capital -- that decrease was offset in part by a $10 million increase in cash earnings. The increase in working capital and other primarily reflects higher accounts receivable from associated companies in the first quarter of 2003 compared with corresponding amounts in the first quarter of 2002 ($81 million). A change in accrued tax liabilities also contributed $52 million to the increase in working capital primarily due to a $48 million increase in tax payments in the first quarter of 2003 compared with the first quarter of 2002. Cash Flows From Financing Activities In the first quarter of 2003, net cash used for financing activities increased to $265 million from $48 million in the same period last year. The increase resulted from the absence of new financing and a reduction of debt (primarily short-term borrowings from associated companies) partially offset by reduced dividends to FirstEnergy. OE had approximately $279.1 million of cash and temporary investments and approximately $175.4 million of short-term indebtedness as of March 31, 2003. Available borrowing capability under bilateral bank facilities totaled $34.0 million as of March 31, 2002. OE had the capability to issue $1.7 billion of additional first mortgage bonds on the basis of 46
property additions and retired bonds. Based upon applicable earnings coverage tests OE could issue up to $3.0 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2003. On April 21, 2003, OE completed a $325 million debt refinancing transaction that included two tranches -- $175 million of 4.00% five year notes and $150 million of 5.45% twelve year notes. The net proceeds will be used to redeem approximately $220 million of outstanding OE first mortgage bonds having a weighted average cost of 7.99%, with the remainder to be used to pay down short-term debt. Cash Flows From Investing Activities Net cash flows received from investing activities totaled $106 million in the first quarter of 2003, compared to a net use of funds of $167 million for the same period of 2002. The $273 million increase in funds from investing activities resulted from payments received on notes from associated companies, offset in part by additional capital expenditures. During the last three quarters of 2003, capital requirements for property additions and capital leases are expected to be about $113 million, including $17 million for nuclear fuel. OE has additional requirements of approximately $234 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including OE. On April 11, 2003, Moody's Investors Service affirmed its existing ratings for FirstEnergy. Moody's noted that the ratings were based on the stable business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for the EUOC, including the OE Companies. Moody's noted that merger debt had put pressure on FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all levels within the company although those plans had been delayed by external events. Other Obligations Obligations not included on OE's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. As of March 31, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $713 million. Equity Price Risk - ----------------- Included in OE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $151 million and $148 million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $15 million reduction in fair value as of March 31, 2003. Outlook - ------- Beginning in 2001, OE's customers were able to select alternative energy suppliers. OE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. 47
Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's Ohio customers elects to obtain power from an alternative supplier, OE reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by the Public Utilities Commission of Ohio (PUCO), Pennsylvania Public Utility Commission and the Federal Energy Regulatory Commission, for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets declined $159.4 million to $1.9 billion on March 31, 2003 from the balance as of December 31, 2002, with $10.6 million of the decrease related to the cumulative entry adopting SFAS 143 at Penn and the balance of the reduction resulting from recovery of transition plan regulatory assets. All of the OE Companies' regulatory assets are expected to continue to be recovered under the provisions of their respective transition plan and rate restructuring plan. The OE Companies' regulatory assets are as follows: Regulatory Assets as of --------------------------------------------------------- March 31, December 31, Company 2003 2002 --------------------------------------------------------- (In millions) OE......................... $1,775.6 $1,855.9 Penn....................... 77.8 156.9 --------------------------------------------------------- Consolidated Total...... $1,853.4 $2,012.8 ========================================================== As part of OE's Ohio transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. OE is also required to provided 560 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within its service area. OE's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. In 2003, the total peak load forecasted for customers electing to stay with OE, including the 560 MW of low cost supply and the load served by OE's affiliate is 5,820 MW. Environmental Matters OE believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from OE's Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2C - Environmental Matters). OE continues to evaluate its compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. OE cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U. S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio, for which hearings began on February 3, 2003. The NOV and complaint allege violations of the Clean Air Act (CAA). The civil complaint against OE and Penn requests installation of "best available control technology" as well as civil penalties of up to $27,500 per day. Although unable to predict the outcome of these proceedings, the OE Companies believe the Sammis Plant is in full compliance with the CAA and that the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the 48
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. OE believes it is in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that requires compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. The effects of compliance on OE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect our earnings and competitive position to the extent OE competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. OE believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Significant Accounting Policies - ------------------------------- OE 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 OE's financial results. All of the OE Companies' assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. The OE Companies' more significant accounting policies are described below. Regulatory Accounting The OE Companies are subject to regulation that sets the prices (rates) they are permitted to charge their customers based on the costs that the 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. As of March 31, 2002, the OE Companies' regulatory assets totaled $1.9 billion. 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. 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 been 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 distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. 49
Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the OE Companies periodically evaluate their long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, the OE Companies recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Recently Issued Accounting Standard Not Yet Implemented - ------------------------------------------------------- FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (OE's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. OE currently has transactions which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. OE currently consolidates the majority of these entities and believe it will continue to consolidate following the adoption of FIN 46. In addition to the entities it is currently consolidating, OE believes that the PNBV Capital Trust, which was used to acquire a portion of the off-balance sheet 50
debt issued in connection with the sale and leaseback of its interest in the Perry Plant and Beaver Valley Unit 2, would require consolidation as a VIE under FIN 46. Ownership of the trust includes a three-percent equity interest by a nonaffiliated party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of OE. Full consolidation of the trust under FIN 46 would change the characterization of the PNBV trust investment to a lease obligation bond investment. Also, consolidation of the outside minority interest would be required, which would increase assets and liabilities by $12.0 million. 51
<TABLE> <CAPTION> THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended March 31, ---------------------------- 2003 2002 --------- --------- (In thousands) <S> <C> <C> OPERATING REVENUES.............................................................. $419,771 $424,977 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 12,659 17,270 Purchased power.............................................................. 136,345 139,436 Nuclear operating costs...................................................... 63,161 71,417 Other operating costs........................................................ 75,809 66,847 -------- -------- Total operation and maintenance expenses................................. 287,974 294,970 Provision for depreciation and amortization.................................. 26,557 28,471 General taxes................................................................ 39,713 38,746 Income taxes................................................................. 9,223 7,468 -------- -------- Total operating expenses and taxes....................................... 363,467 369,655 -------- -------- OPERATING INCOME................................................................ 56,304 55,322 OTHER INCOME.................................................................... 4,741 5,241 -------- -------- .......... INCOME BEFORE NET INTEREST CHARGES.............................................. 61,045 60,563 -------- -------- NET INTEREST CHARGES: Interest on long-term debt................................................... 40,640 46,995 Allowance for borrowed funds used during construction........................ (2,167) (749) Other interest expense (credit).............................................. 31 (529) Subsidiary's preferred dividend requirements................................. 2,250 2,150 -------- -------- Net interest charges..................................................... 40,754 47,867 -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 20,291 12,696 Cumulative effect of accounting change (Net of income taxes of $30,168,000) (Note 5) 42,378 -- -------- -------- NET INCOME...................................................................... 62,669 12,696 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... (759) 8,256 -------- -------- EARNINGS ON COMMON STOCK........................................................ $ 63,428 $ 4,440 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements. </FN> </TABLE> 52
<TABLE> <CAPTION> THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ----------- ------------ (In thousands) <S> <C> <C> ASSETS ------ UTILITY PLANT: In service................................................................ $4,114,337 $4,045,465 Less--Accumulated provision for depreciation.............................. 1,834,329 1,824,884 ---------- ---------- 2,280,008 2,220,581 ---------- ---------- Construction work in progress- Electric plant.......................................................... 164,966 153,104 Nuclear fuel............................................................ 44,406 45,354 ---------- ---------- 209,372 198,458 ---------- ---------- 2,489,380 2,419,039 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust................................................ 416,836 435,907 Nuclear plant decommissioning trusts...................................... 234,855 230,527 Long-term notes receivable from associated companies...................... 102,860 102,978 Other..................................................................... 20,914 21,004 ---------- ---------- 775,465 790,416 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 826 30,382 Receivables- Customers............................................................... 14,184 11,317 Associated companies.................................................... 63,946 74,002 Other (less accumulated provisions of $1,015,000 for uncollectible accounts at both dates)............................................... 126,322 134,375 Notes receivable from associated companies................................ 565 447 Materials and supplies, at average cost- Owned................................................................... 18,356 18,293 Under consignment....................................................... 38,159 38,094 Prepayments and other..................................................... 2,445 4,217 ---------- ---------- 264,803 311,127 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 943,331 939,804 Goodwill.................................................................. 1,370,639 1,370,639 Property taxes............................................................ 79,430 79,430 Other..................................................................... 25,065 24,798 ---------- ---------- 2,418,465 2,414,671 ---------- ---------- $5,948,113 $5,935,253 ========== ========== </TABLE> 53
<TABLE> <CAPTION> THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ---------- ------------ (In thousands) <S> <C> <C> CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: Common stockholder's equity- Common stock, without par value, authorized 105,000,000 shares - 79,590,689 shares outstanding......................................... $ 981,962 $ 981,962 Accumulated other comprehensive loss.................................... (46,585) (44,051) Retained earnings....................................................... 352,173 288,721 ---------- ---------- Total common stockholder's equity................................... 1,287,550 1,226,632 Preferred stock- Not subject to mandatory redemption..................................... 96,404 96,404 Subject to mandatory redemption......................................... 5,019 5,021 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures......... 100,000 100,000 Long-term debt............................................................ 1,972,400 1,975,001 ---------- ---------- 3,461,373 3,403,058 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 343,199 388,190 Accounts payable- Associated companies.................................................... 229,544 267,664 Other................................................................... 8,574 14,583 Notes payable to associated companies..................................... 321,828 288,583 Accrued taxes............................................................. 129,158 126,262 Accrued interest.......................................................... 60,611 51,767 Other..................................................................... 35,694 64,324 ---------- ---------- 1,128,608 1,201,373 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 692,278 659,044 Accumulated deferred investment tax credits............................... 71,160 72,125 Nuclear plant decommissioning costs....................................... -- 239,720 Asset retirement obligation............................................... 242,208 -- Retirement benefits....................................................... 173,765 171,968 Other..................................................................... 178,721 187,965 ---------- ---------- 1,358,132 1,330,822 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $5,948,113 $5,935,253 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these balance sheets. </FN> </TABLE> 54
<TABLE> <CAPTION> THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended March 31, 2003 2002 -------- --------- (In thousands) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 62,669 $ 12,696 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization.............................. 26,557 28,471 Nuclear fuel and lease amortization...................................... 5,044 5,990 Other amortization....................................................... (4,613) (3,892) Deferred income taxes, net............................................... 35,474 7,196 Investment tax credits, net.............................................. (965) (902) Receivables.............................................................. 15,242 6,816 Materials and supplies................................................... (128) (1,366) Accounts payable......................................................... (44,129) 18,322 Cumulative effect of accounting change................................... (72,547) -- Accrued taxes............................................................ 2,896 (5,068) Accrued interest......................................................... 8,844 5,569 Prepayments and other.................................................... 1,772 22,508 Deferred rents and sale/leaseback........................................ (26,603) 14,877 Other.................................................................... (4,693) (23,695) -------- --------- Net cash provided from operating activities............................ 4,820 87,522 -------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net................................................. 33,245 75,484 Redemptions and Repayments- Preferred Stock............................................................ -- (100,000) Long-term debt............................................................. (45,103) (94) Dividend Payments- Preferred stock............................................................ (1,865) (5,252) -------- --------- Net cash provided from (used for) financing activities................. (13,723) (29,862) -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (31,218) (36,470) Capital trust investments.................................................... 19,071 -- Other........................................................................ (8,506) (6,224) -------- --------- Net cash provided from (used for) investing activities................. (20,653) (42,694) -------- --------- Net increase (decrease) in cash and cash equivalents............................ (29,556) 14,966 Cash and cash equivalents at beginning of period ............................... 30,382 296 -------- --------- Cash and cash equivalents at end of period...................................... $ 826 $ 15,262 ======== ========= <FN> The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements. </FN> </TABLE> 55
REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors 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 March 31, 2003, and the related consolidated statements of income and cash flows for the three-month periods ended March 31, 2003 and 2002. These interim 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 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. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003 56
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in portions of Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain them as their power supplier. CEI provides power directly to alternative energy suppliers under CEI's transition plan. CEI has unbundled 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 - --------------------- Earnings on common stock in the first quarter of 2003 increased to $63.4 million from $4.4 million in the first quarter of 2002. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $42.4 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $20.3 million in the first quarter of 2003, compared to $12.7 million for the same period of 2002. Operating revenues decreased by $5.2 million or 1.2% in the first quarter of 2003 from the same period in 2002. The lower revenues resulted from reduced kilowatt-hour sales, which were partially offset by the effects of colder weather on distribution deliveries to residential and commercial customers. Kilowatt-hour sales to retail customers declined by 4.3% in the first quarter of 2003 from the same quarter of 2002, which reduced generation sales revenue by $6.6 million. Electric generation services provided by alternative suppliers as a percent of total sales deliveries in CEI's franchise area increased to 37.6% in the first quarter of 2003 from 28.5% in the first quarter of 2002. Distribution deliveries increased 10.5% in the first quarter of 2003 compared to the corresponding quarter of 2002, with increases in all customer sectors (residential, commercial and industrial). As a result, revenues from electricity throughput increased by $15.5 million in the first quarter of 2003 from the same quarter of the prior year. The increase reflected higher volumes, offset in part by lower unit prices. Distribution deliveries to residential and commercial customers benefited from colder than normal weather, while a substantial increase in distribution deliveries to industrial customers, despite the continued effect of a sluggish economy, resulted from an expansion of steel production in the franchise area. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, reduced operating revenues -- $5.8 million in the first quarter of 2003 compared with the corresponding period of 2002. These revenue reductions are deferred for future recovery under CEI's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers decreased by $10.7 million (primarily to FES) in the first quarter of 2003 compared with the first quarter of 2002, due to reduced nuclear generation from the extended outage of the Davis-Besse Plant (see Davis-Besse Restoration). 57
Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the first quarter of 2002 are summarized in the following table:
Changes in Kilowatt-Hour Sales ---------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. (4.3)% Wholesale............................... (17.8)% - ---------------------------------------------------------------------- Total Electric Generation Sales........... (11.3)% ==================================================== Distribution Deliveries: Residential............................. 12.9% Commercial.............................. 7.0% Industrial.............................. 10.9% - ---------------------------------------------------------------------- Total Distribution Deliveries............. 10.5% ==================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $6.2 million in the first quarter of 2003 from the first quarter of 2002. The following table presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes ------------------------------------------------------------------ Increase (Decrease) (In millions) Fuel............................................. $(4.6) Purchased power costs............................ (3.1) Nuclear operating costs.......................... (8.3) Other operating costs............................ 9.0 -------------------------------------------------------------- Total operation and maintenance expenses....... (7.0) Provision for depreciation and amortization...... (1.9) General taxes.................................... 1.0 Income taxes..................................... 1.7 -------------------------------------------------------------- Total operating expenses and taxes............. $(6.2) =============================================================== Lower fuel costs in the first quarter of 2003, compared with the first quarter of 2002 resulted from reduced nuclear generation (down 21%). The lower purchased power costs reflected reduced unit costs offset in part by additional kilowatt-hours purchased. Two scheduled refueling outages in the first quarter of 2002 (Beaver Valley Unit 2 and Davis-Besse) and the absence of refueling outages in the first quarter of 2003 more than offset incremental costs associated with the extended outage of Davis-Besse, producing the lower nuclear operating costs. The increase in other operating costs resulted in part from higher employee benefit costs. The decrease in depreciation and amortization charges in the first quarter of 2003, compared with the first quarter of 2002 was attributable to several factors - higher shopping incentive deferrals ($5.8 million) and lower charges resulting from the implementation of SFAS 143 ($3.0 million), including revised service life assumptions for generating plants ($4.0 million). Partially offsetting these decreases were increased amortization of regulatory assets being recovered under CEI's transition plan ($3.6 million) and recognition of depreciation on three fossil plants ($8.1 million), which had been held pending sale in the first quarter of 2002 but were subsequently retained by FirstEnergy in the fourth quarter of 2002. Net Interest Charges Net interest charges continued to trend lower, decreasing by $7.1 million in the first quarter of 2003 from the same quarter last year, reflecting redemptions and refinancings since the end of the first quarter of 2002. CEI's net debt redemptions totaled $15.0 million during the first quarter of 2003 which will result in annualized savings of $1.2 million. Cumulative Effect of Accounting Changes Upon adoption of SFAS 143 in the first quarter of 2003, CEI recorded an after-tax credit to net income of $42.4 million. CEI identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $49.9 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $6.8 million. The 58
asset retirement obligation liability at the date of adoption was $238.3 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, CEI had recorded decommissioning liabilities of $239.7 million, including unrealized gains on the decommissioning trust funds of $0.4 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $72.5 million increase to income, or $42.4 million net of income taxes. Unrealized gains on decommissioning trust investments ($0.2 million net of tax) formerly included in the decommissioning liability balances as of December 31, 2002 were offset against OCI upon adoption of SFAS 143 (see Note 5). Preferred Stock Dividend Requirements Preferred stock dividend requirements decreased $9.0 million in the first quarter of 2003, compared to the same period last year, principally due to optional redemptions of preferred stock in 2002. Capital Resources and Liquidity - ------------------------------- CEI's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, CEI expects to meet its contractual obligations with cash from operations. Thereafter, CEI expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2003, CEI had $0.8 million of cash and cash equivalents, compared with $30.4 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from operating activities during the first quarter of 2003, compared with the first quarter of 2002 were as follows: Operating Cash Flows 2003 2002 ----------------------------------------------------------- (In millions) Cash earnings (1).................... $ 52 $50 Working capital and other............ (47) 38 ----------------------------------------------------------- Total................................ $ 5 $88 =========================================================== (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities decreased $83 million due to an $85 million increase in working capital - that decrease was offset in part by a $2 million increase in cash earnings. The largest factors contributing to the increase in working capital and other were lower accounts payable from associated companies in the first quarter of 2003 compared with corresponding amounts in the first quarter of 2002 ($68 million). Cash Flows From Financing Activities Net cash used for financing activities declined $16 million in the first quarter of 2003 from the first quarter of 2002. The decrease in funds used for financing activities primarily reflected lower security redemptions and repayments, which were partially offset by a net reduction in short-term borrowings. CEI had about $1.4 million of cash and temporary investments and approximately $321.8 million of short-term indebtedness as of March 31, 2003. CEI had the capability to issue $545.5 million of additional first mortgage bonds on the basis of property additions and retired bonds. CEI has no restrictions on the issuance of preferred stock. Cash Flows From Investing Activities Net cash used for investing activities decreased $22 million in the first quarter of 2003 from the same quarter of 2002 due to a reduction in the Shippingport Capital Trust investment and lower capital expenditures. 59
During the last three quarters of 2003, capital requirements for property additions and capital leases are expected to be about $85 million, including $9 million for nuclear fuel. CEI has additional requirements of approximately $101 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including CEI. On April 11, 2003 Moody's Investors Service affirmed its existing ratings for FirstEnergy. Moody's noted that the ratings were based on the stable business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for the EUOC, including CEI. Moody's noted that merger debt had put pressure on FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all levels within the company although those plans had been delayed by external events. Other Obligations Obligations not included on CEI's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of March 31, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $157 million. CEI sells substantially all of its retail customer receivables, which provided $96 million of off-balance sheet financing as of March 31, 2003. Equity Price Risk - ----------------- Included in CEI's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $117 million and $119 million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12 million reduction in fair value as of March 31, 2003. Outlook - ------- Beginning in 2001, CEI's customers were able to select alternative energy suppliers. CEI continues to deliver power to residential homes and businesses through its existing distribution systems, which remain regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio CEI has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of CEI's customers elects to obtain power from an alternative supplier, CEI reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. CEI has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by the PUCO and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets increased $3.5 million to $943.3 million as of March 31, 2003 from the balance as of December 31, 2002. All of CEI's regulatory assets are expected to continue to be recovered under the provisions of its transition plan. 60
As part of CEI's Ohio transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. CEI is also required to provide 400 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within its service area. CEI's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FirstEnergy is also accelerating maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy discussed plans to test the bottom of the reactor for leaks and to install a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FirstEnergy anticipates that the unit will be ready for restart in the first half of the summer of 2003. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed FirstEnergy's plans to reduce debt levels FirstEnergy believes such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). Incremental expenses associated with the extended Davis-Besse outage in the first quarter of 2003 totaled $88.6 million, including $36.3 million for maintenance work and $52.3 million for fuel and purchased power. CEI's ownership share is 51.38% of those expenses. It is anticipated that an additional $13.7 million in maintenance costs will be spent during the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month in the non-summer months and $20-25 million per month during the summer. Environmental Matters CEI believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from its generating facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2 - Environmental Matters). CEI continues to evaluate its compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. CEI cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. CEI has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. 61
Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, 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's total accrued liabilities were approximately $2.5 million as of March 31, 2003. The effects of compliance on CEI with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect its earnings and competitive position to the extent CEI competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. CEI believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Legal Matters Various lawsuits, claims and proceedings related to CEI's normal business operations are pending against CEI, the most significant of which are described above. Significant Accounting Policies - ------------------------------- CEI 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 CEI's financial results. All of CEI'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 those 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 its customers based on the costs that the 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. As of March 31, 2003, CEI's regulatory assets totaled $943.3 million. CEI regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition CEI follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet been 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 distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these 62
factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," CEI periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset, is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, CEI recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, CEI evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur CEI would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. CEI's annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill. The forecasts used in CEI's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of March 31, 2003, CEI had approximately $1.4 billion of goodwill. Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (CEI's third 63
quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. CEI currently has transactions which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. CEI currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. One of these entities CEI is currently consolidating is the Shippingport Capital Trust which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of its interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated parties and a 0.34 percent equity interest by Toledo Edison Capital Corp., an affiliated company. 64
<TABLE> <CAPTION> THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended March 31, ------------------------- 2003 2002 -------- -------- (In thousands) <S> <C> <C> OPERATING REVENUES.............................................................. $231,822 $244,167 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 7,681 11,391 Purchased power.............................................................. 74,251 82,404 Nuclear operating costs...................................................... 65,980 75,098 Other operating costs........................................................ 39,592 34,879 -------- -------- Total operation and maintenance expenses................................. 187,504 203,772 Provision for depreciation and amortization.................................. 20,240 21,368 General taxes................................................................ 15,008 13,748 Income taxes (benefit)....................................................... (1,557) (4,379) -------- -------- Total operating expenses and taxes....................................... 221,195 234,509 -------- -------- OPERATING INCOME................................................................ 10,627 9,658 OTHER INCOME.................................................................... 3,100 4,343 -------- -------- INCOME BEFORE NET INTEREST CHARGES.............................................. 13,727 14,001 -------- -------- NET INTEREST CHARGES: Interest on long-term debt................................................... 11,815 15,872 Allowance for borrowed funds used during construction........................ (1,306) (428) Other interest expense (credit).............................................. 168 (735) -------- -------- Net interest charges..................................................... 10,677 14,709 -------- -------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................... 3,050 (708) Cumulative effect of accounting change (net of income taxes of $18,201,000) (Note 5) ........................................................ 25,550 -- -------- -------- NET INCOME (LOSS)............................................................... 28,600 (708) -------- -------- PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 1,605 4,724 -------- -------- EARNINGS (LOSSES) ATTRIBUTABLE TO COMMON STOCK.................................. $ 26,995 $ (5,432) ======== ======== <FN> The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. </FN> </TABLE> 65
<TABLE> <CAPTION> THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ---------- ------------ (In thousands) ASSETS ------ <S> <C> <C> UTILITY PLANT: In service................................................................ $1,655,389 $1,600,860 Less--Accumulated provision for depreciation.............................. 723,821 706,772 ---------- ---------- 931,568 894,088 ---------- ---------- Construction work in progress- Electric plant.......................................................... 110,267 104,091 Nuclear fuel............................................................ 30,464 33,650 ---------- ---------- 140,731 137,741 ---------- ---------- 1,072,299 1,031,829 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust................................................ 223,335 240,963 Nuclear plant decommissioning trusts...................................... 179,511 174,514 Long-term notes receivable from associated companies...................... 162,109 162,159 Other..................................................................... 2,172 2,236 ---------- ---------- 567,127 579,872 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 1,445 20,688 Receivables- Customers............................................................... 5,640 4,711 Associated companies.................................................... 44,275 55,245 Other................................................................... 4,570 6,778 Notes receivable from associated companies................................ 6,452 1,957 Materials and supplies, at average cost- Owned................................................................... 13,768 13,631 Under consignment....................................................... 23,587 22,997 Prepayments and other..................................................... 8,576 3,455 ---------- ---------- 108,313 129,462 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 387,130 392,643 Goodwill.................................................................. 445,732 445,732 Property taxes............................................................ 23,429 23,429 Other..................................................................... 14,641 14,257 ---------- ---------- 870,932 876,061 ---------- ---------- $2,618,671 $2,617,224 ========== ========== </TABLE> 66
<TABLE> <CAPTION> THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ---------- ------------ (In thousands) <S> <C> <C> CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: Common stockholder's equity- Common stock, $5 par value, authorized 60,000,000 shares - 39,133,887 shares outstanding......................................... $ 195,670 $ 195,670 Other paid-in capital................................................... 428,559 428,559 Accumulated other comprehensive loss.................................... (21,638) (21,115) Retained earnings....................................................... 136,812 109,817 ---------- ---------- Total common stockholder's equity................................... 739,403 712,931 Preferred stock not subject to mandatory redemption....................... 126,000 126,000 Long-term debt............................................................ 556,080 557,265 ---------- ---------- 1,421,483 1,396,196 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 115,755 189,355 Accounts payable- Associated companies.................................................... 120,483 171,862 Other................................................................... 6,100 8,638 Notes payable to associated companies..................................... 248,045 149,653 Accrued taxes............................................................. 40,712 34,967 Accrued interest.......................................................... 14,978 16,377 Other..................................................................... 52,416 57,232 ---------- ---------- 598,489 628,084 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 246,517 223,087 Accumulated deferred investment tax credits............................... 28,993 29,491 Nuclear plant decommissioning costs....................................... -- 180,856 Asset retirement obligation............................................... 174,877 -- Retirement benefits....................................................... 83,324 82,553 Other..................................................................... 64,988 76,957 ---------- ---------- 598,699 592,944 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Note 2)....................................... ---------- ---------- $2,618,671 $2,617,224 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets. </FN> </TABLE> 67
<TABLE> <CAPTION> THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended March 31, -------------------------- 2003 2002 -------- -------- (In thousands) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)............................................................... $ 28,600 $ (708) Adjustments to reconcile net income (loss) to net cash from operating activities- Provision for depreciation and amortization.............................. 20,240 21,368 Nuclear fuel and lease amortization...................................... 2,768 3,573 Deferred income taxes, net............................................... 22,675 5,314 Investment tax credits, net.............................................. (498) (486) Receivables.............................................................. 12,249 20,022 Materials and supplies................................................... (727) (651) Accounts payable......................................................... (53,917) 2,861 Cumulative effect of accounting change................................... (43,751) -- Accrued taxes............................................................ 5,745 (5,710) Accrued interest......................................................... (1,399) (2,030) Prepayments and other.................................................... (5,121) 9,987 Deferred rents and sale/leaseback........................................ (1,522) 24,878 Other.................................................................... (15,293) (12,653) -------- -------- Net cash provided from (used for) operating activities................. (29,951) 65,765 -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net................................................. 98,392 68,998 Redemptions and Repayments- Preferred stock............................................................ -- (85,299) Long-term debt............................................................. (73,600) (94) Dividend Payments- Common stock............................................................... -- (5,600) Preferred stock............................................................ (2,211) (3,425) -------- -------- Net cash provided from (used for) financing activities................. 22,581 (25,420) -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (17,242) (25,559) Loans to associated companies................................................ (4,445) (6,301) Capital trust investments.................................................... 17,628 (57) Other........................................................................ (7,814) (6,121) -------- -------- Net cash provided from (used for) investing activities................. (11,873) (38,038) -------- -------- Net increase (decrease) in cash and cash equivalents............................ (19,243) 2,307 Cash and cash equivalents at beginning of period................................ 20,688 302 -------- -------- Cash and cash equivalents at end of period...................................... $ 1,445 $ 2,609 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. </FN> </TABLE> 68
REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of The Toledo Edison Company: We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of March 31, 2003, and the related consolidated statements of income and cash flows for the three-month periods ended March 31, 2003 and 2002. These interim 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 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. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003 69
THE TOLEDO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE conducts business in portions of Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain them as their power supplier. TE provides power directly to wholesale customers under previously negotiated contracts, as well as to alternative energy suppliers under TE's transition plan. TE has unbundled 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 Earnings on common stock in the first quarter of 2003 increased to $27.0 million from a loss of $5.4 million in the first quarter of 2002. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $25.6 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $3.1 million in the first quarter of 2003, compared to a net loss of $0.7 million for the same period of 2002. Improved results in the first quarter of 2003 reflected reduced financing costs and lower operating expenses. Substantially offsetting these improvements were lower operating revenues from reduced kilowatt-hour sales. Operating revenues decreased by $12.3 million or 5.1% in the first quarter of 2003 from the same period in 2002. The lower revenues resulted from reduced kilowatt-hour sales which were partially offset by the effects of colder weather on distribution deliveries to residential and commercial customers. Kilowatt-hour sales to retail customers declined by 3.5% in the first quarter of 2003 from the same quarter of 2002, which reduced generation sales revenue by $11.6 million. Electric generation services provided by alternative suppliers as a percent of total sales deliveries in TE's franchise area increased to 21.8% in the first quarter of 2003 from 14.4% in the first quarter of 2002. Distribution deliveries increased 5.8% in the first quarter of 2003 compared to the corresponding quarter of 2002, with increases in all customer sectors (residential, commercial and industrial). As a result, revenues from electricity throughput increased by $20.7 million in the first quarter of 2003 from the first quarter of 2002. The increase reflected higher unit prices, which accounted for two-thirds of the increase and higher volumes. Distribution deliveries benefited from substantially higher residential and commercial demand, due in larger part to colder than normal weather, that was moderated by the continued effect of a sluggish economy and its impact on demand by industrial customers in TE's franchise area. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, reduced operating revenues by $2.2 million in the first quarter of 2003 compared with the same period last year. These revenue reductions are deferred for future recovery under TE's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers decreased by $21.0 million (primarily to FES) in the first quarter of 2003 compared with the first quarter of 2002, due to reduced nuclear generation from the extended outage of the Davis-Besse Plant (see Davis-Besse Restoration). Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the first quarter of 2002 are summarized in the following table: 70
Changes in Kilowatt-Hour Sales ---------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (3.5)% Wholesale............................. (28.1)% - ---------------------------------------------------------------------- Total Electric Generation Sales........... (15.2)% ==================================================== Distribution Deliveries: Residential........................... 10.9% Commercial............................ 11.7% Industrial............................ 0.3% - --------------------------------------------------------------------- Total Distribution Deliveries............. 5.8% =================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $13.3 million in the first quarter of 2003 from the first quarter of 2002. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes ------------------------------------------------------------------ Increase (Decrease) (In millions) Fuel............................................. $ (3.7) Purchased power costs............................ (8.2) Nuclear operating costs.......................... (9.1) Other operating costs............................ 4.7 -------------------------------------------------------------- Total operation and maintenance expenses....... (16.3) Provision for depreciation and amortization...... (1.1) General taxes.................................... 1.3 Income taxes..................................... 2.8 -------------------------------------------------------------- Total operating expenses and taxes............. $(13.3) ===============================================================
Lower fuel costs in the first quarter of 2003, compared with the same quarter of 2002, resulted from reduced nuclear generation (down 30%). The lower purchased power costs reflected fewer kilowatt-hours required for customer needs. Two scheduled refueling outages in the first quarter of 2002 (Beaver Valley Unit 2 and Davis-Besse) and the absence of refueling outages in the first quarter of 2003 more than offset incremental costs associated with the extended outage of Davis-Besse, producing the lower nuclear operating costs. The increase in other operating costs resulted in part from higher employee benefit costs. Charges for depreciation and amortization decreased slightly in the first quarter of 2003 compared with the first quarter of 2002, was attributable to several factors - higher shopping incentive deferrals ($2.2 million) and lower charges resulting from the implementation of SFAS 143 ($4.0 million), including revised service life assumptions for generating plants ($3.0 million). Nearly offsetting these decreases were increased amortization of regulatory assets being recovered under TE's transition plan ($5.3 million) and recognition of depreciation on the Bay Shore generating plant ($1.5 million), which had been held pending sale in the first quarter of 2002 but was subsequently retained by FirstEnergy in the fourth quarter of 2002. Net Interest Charges Net interest charges continued to trend lower, decreasing by $4.0 million in the first quarter of 2003 from the same period last year, reflecting security redemptions and refinancings since the end of the first quarter of 2002. TE's net debt redemptions totaled $53.4 million during the first quarter of 2003, which will result in annualized savings of $4.2 million. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded an after-tax credit to net income of $25.6 million. TE identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $41.1 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $5.5 million. The asset retirement obligation liability at the date of adoption was $172 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, TE had recorded decommissioning liabilities of $180.8 million, including 71
unrealized gains on the decommissioning trust funds of $1.9 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $43.8 million increase to income, or $25.6 million net of income taxes. Unrealized gains on decommissioning trust investments ($1.1 million net of tax) formerly included in the decommissioning liability balances as of December 31, 2002 were offset against OCI upon the adoption of SFAS 143 (see Note 5). Capital Resources and Liquidity - ------------------------------- TE's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, TE expects to meet its contractual obligations with cash from operations. Thereafter, TE expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2003, TE had $1.4 million of cash and cash equivalents, compared with $20.7 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided by (used for) operating activities during the first quarter of 2003, compared with the corresponding period in 2002 were as follows: Operating Cash Flows 2003 2002 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 30 $29 Working capital and other............ (60) 37 ------------------------------------------------------------- Total................................ $(30) $66 ============================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash used for operating activities was $30 million in the first quarter of 2003, a $96 million change from the $66 million provided by operating activities in the first quarter of 2002. The decrease in funds from operating activities resulted from a $97 million increase in working capital - principally reduced accounts payable (primarily to associated companies) which contributed $56.8 million to the increase in working capital requirements. Cash Flows From Financing Activities In the first quarter of 2003, net cash provided from financing activities increased to $23 million from net cash used for financing of $25 million in the first quarter of 2002. The increase in cash provided from financing activities primarily resulted from additional short-term borrowings from associated companies and a slight reduction in security redemptions and repayments. TE had approximately $7.9 million of cash and temporary investments and approximately $248 million of short-term indebtedness as of March 31, 2003. TE is currently precluded from issuing first mortgage bonds or preferred stock based upon applicable earnings coverage tests as of March 31, 2003. Cash Flows From Investing Activities Net cash used for investing activities decreased $26 million between the first quarter of 2003 and the same quarter of 2002 due to reduced capital expenditures and a reduction in the Shippingport Capital Trust investment. During the last three quarters of 2003, capital requirements for property additions and capital leases are expected to be about $52 million, including $9 million for nuclear fuel. TE has additional requirements of approximately $43 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. 72
On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including TE. On April 11, 2003 Moody's Investors Service affirmed its existing ratings for FirstEnergy. Moody's noted that the ratings were based on the stable business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for the EUOC, including TE. Moody's noted that merger debt had put pressure on FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all levels within the company although those plans had been delayed by external events. Other Obligations Obligations not included on TE's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of March 31, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, totaled $509 million. TE sells substantially all of its retail customer receivables, which provided $49 million of off-balance sheet financing as of March 31, 2003. Equity Price Risk - ----------------- Included in TE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $90 million as of March 31, 2003 and December 31, 2002. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $9 million reduction in fair value as of March 31, 2003. Outlook - ------- Beginning in 2001, TE's customers were able to select alternative energy suppliers. TE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. TE has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of TE's Ohio customers elects to obtain power from an alternative supplier, TE reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. TE has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by The Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets declined $5.5 million to $387.1 million as of March 31, 2003 from the balance as of December 31, 2002, resulting from recovery of transition plan regulatory assets. As part of TE's transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. TE is also required to provided 160 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within its service area. TE's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. 73
Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FirstEnergy is also accelerating maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy discussed plans to test the bottom of the reactor for leaks and to install a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FirstEnergy anticipates that the unit will be ready for restart in the first half of the summer of 2003 after completion of the additional maintenance work and regulatory reviews. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed FirstEnergy's plans to reduce debt levels FirstEnergy believes such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). Incremental expenses associated with the extended Davis-Besse outage in the first quarter of 2003 totaled $88.6 million, including $36.3 million for maintenance work and $52.3 million for fuel and purchased power. TE's ownership share is 48.62% of those expenses. It is anticipated that an additional $13.7 million in maintenance costs will be spent during the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month in the non-summer months and $20-25 million per month during the summer. Environmental Matters TE believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2C - Environmental Matters). TE continues to evaluate its compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. TE believes it is in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the 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 74
eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that requires compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. TE has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved, are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, 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 total accrued liabilities of approximately $0.2 million as of March 31, 2003. The effects of compliance on TE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect its earnings and competitive position to the extent TE competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. TE believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Legal Matters Various lawsuits, claims and proceedings relayed to TE's normal business operations are pending against TE, the most significant of which are described above. Significant Accounting Policies - ------------------------------- TE 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 TE's financial results. All of TE'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 those 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 its customers based on the costs that the 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. As of March 31, 2003, TE's regulatory assets totaled $387.1 million. TE regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition TE follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet been 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 distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. 75
Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," TE periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, TE recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, TE evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur, TE would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. TE's annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill. The forecasts used in TE's annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill. The forecasts used in TE's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of March 31, 2003, TE had approximately $446 million of goodwill. Recently Issued Accounting Standard Not Yet Implemented - ------------------------------------------------------- FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (TE's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. 76
TE currently has transactions which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. TE currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. One of these entities TE is currently consolidating is the Shippingport Capital Trust, which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of its interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated parties and a 0.34 percent equity interest by Toledo Edison Capital Corp., a majority owned subsidiary. 77
<TABLE> <CAPTION> PENNSYLVANIA POWER COMPANY STATEMENTS OF INCOME (Unaudited) Three Months Ended March 31, ------------------------- 2003 2002 -------- -------- (In thousands) <S> <C> <C> OPERATING REVENUES.............................................................. $128,343 $124,335 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 4,713 6,333 Purchased power.............................................................. 44,066 39,963 Nuclear operating costs...................................................... 46,929 22,332 Other operating costs........................................................ 16,550 9,952 -------- -------- Total operation and maintenance expenses................................. 112,258 78,580 Provision for depreciation and amortization.................................. 13,265 14,204 General taxes................................................................ 6,179 6,004 Income taxes (benefit)....................................................... (1,479) 10,416 -------- -------- Total operating expenses and taxes....................................... 130,223 109,204 -------- -------- OPERATING INCOME (LOSS)......................................................... (1,880) 15,131 OTHER INCOME.................................................................... 561 665 -------- -------- INCOME (LOSS) BEFORE NET INTEREST CHARGES....................................... (1,319) 15,796 -------- -------- NET INTEREST CHARGES: Interest expense............................................................. 4,064 4,098 Allowance for borrowed funds used during construction........................ (629) (252) -------- -------- Net interest charges..................................................... 3,435 3,846 -------- -------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................... (4,754) 11,950 Cumulative effect of accounting change (net of income taxes of $7,532,000) (Note 5) 10,618 -- -------- -------- NET INCOME...................................................................... 5,864 11,950 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 912 926 -------- -------- EARNINGS ON COMMON STOCK........................................................ $ 4,952 $ 11,024 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements. </FN> </TABLE> 78
<TABLE> <CAPTION> PENNSYLVANIA POWER COMPANY BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ----------- ------------ (In thousands) <S> <C> <C> ASSETS ------ UTILITY PLANT: In service................................................................ $761,120 $680,729 Less--Accumulated provision for depreciation.............................. 310,711 316,424 -------- -------- 450,409 364,305 -------- -------- Construction work in progress- Electric plant.......................................................... 58,232 44,696 Nuclear fuel............................................................ 22,071 8,812 -------- -------- 80,303 53,508 -------- -------- 530,712 417,813 -------- -------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 119,270 119,401 Long-term notes receivable from associated companies...................... 38,823 38,921 Other..................................................................... 2,477 2,569 -------- -------- 160,570 160,891 -------- -------- CURRENT ASSETS: Cash and cash equivalents................................................. 1,827 1,222 Receivables- Customers (less accumulated provisions of $719,000 and $702,000, respectively, for uncollectible accounts)............................. 43,130 44,341 Associated companies.................................................... 29,364 42,652 Other................................................................... 2,499 5,262 Notes receivable from associated companies................................ 30,494 35,317 Materials and supplies, at average cost................................... 30,740 30,309 Prepayments............................................................... 21,634 5,346 -------- -------- 159,688 164,449 -------- -------- DEFERRED CHARGES: Regulatory assets......................................................... 77,776 156,903 Other..................................................................... 7,616 7,692 -------- -------- 85,392 164,595 -------- -------- $936,362 $907,748 ======== ======== </TABLE> 79
<TABLE> <CAPTION> PENNSYLVANIA POWER COMPANY BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ----------- ------------ (In thousands) <S> <C> <C> 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) Accumulated other comprehensive loss.................................... (9,932) (9,932) Retained earnings....................................................... 42,868 50,916 -------- -------- Total common stockholder's equity................................... 221,326 229,374 Preferred stock- Not subject to mandatory redemption..................................... 39,105 39,105 Subject to mandatory redemption......................................... 13,500 13,500 Long-term debt............................................................ 171,508 185,499 -------- -------- 445,439 467,478 -------- -------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 80,539 66,556 Accounts payable- Associated companies.................................................... 85,791 52,653 Other................................................................... 436 5,730 Accrued taxes............................................................. 16,778 12,507 Accrued interest.......................................................... 3,549 5,558 Other..................................................................... 9,865 10,479 -------- -------- 196,958 153,483 -------- -------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 120,591 117,385 Accumulated deferred investment tax credits............................... 3,737 3,810 Asset retirement obligation............................................... 123,358 -- Nuclear plant decommissioning costs....................................... -- 119,863 Other..................................................................... 46,279 45,729 -------- -------- 293,965 286,787 -------- -------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... -------- -------- $936,362 $907,748 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets. </FN> </TABLE> 80
<TABLE> <CAPTION> PENNSYLVANIA POWER COMPANY STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended March 31, -------------------------- 2003 2002 -------- -------- (In thousands) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 5,864 $ 11,950 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization................................ 13,265 14,204 Nuclear fuel and lease amortization........................................ 3,583 4,716 Deferred income taxes, net................................................. 6,122 (1,925) Investment tax credits, net................................................ (620) (665) Cumulative effect of accounting change (Note 5)............................ (18,150) -- Receivables................................................................ 17,262 (682) Materials and supplies..................................................... (431) (572) Accounts payable........................................................... 27,844 (15,759) Accrued taxes.............................................................. 4,271 10,650 Accrued interest........................................................... (2,009) (1,638) Prepayments and other...................................................... (16,288) (13,470) Other...................................................................... (380) (274) -------- -------- Net cash provided from operating activities............................ 40,333 6,535 -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Redemptions and Repayments- Long-term debt............................................................. (16) (40,667) Dividend Payments- Common stock............................................................... (13,000) (7,800) Preferred stock............................................................ (912) (926) -------- -------- Net cash provided from (used for) financing activities................. (13,928) (49,393) -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (31,054) (8,083) Notes receivable from associated companies, net.............................. 4,921 53,063 Other........................................................................ 333 (1,188) -------- -------- Net cash provided from (used for) investing activities................. (25,800) 43,792 -------- -------- Net increase (decrease) in cash and cash equivalents............................ 605 934 Cash and cash equivalents at beginning of period................................ 1,222 67 -------- -------- Cash and cash equivalents at end of period...................................... $ 1,827 $ 1,001 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements. </FN> </TABLE> 81
REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Pennsylvania Power Company: We have reviewed the accompanying balance sheet of Pennsylvania Power Company as of March 31, 2003, and the related statements of income and cash flows for the three-month periods ended March 31, 2003 and 2002. These interim 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 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. We previously audited in accordance with auditing standards generally accepted in the United States of America, the balance sheet and the statement of capitalization as of December 31, 2002, and the related statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003 82
PENNSYLVANIA POWER COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Penn is a wholly owned, electric utility subsidiary of OE. Penn conducts business in western Pennsylvania, providing regulated electric distribution services. Penn also provides generation services to those customers electing to retain it as their power supplier. Penn provides power directly to wholesale customers under previously negotiated contracts. Penn has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Its power supply requirements are provided by FES - an affiliated company. Results of Operations - --------------------- Earnings on common stock in the first quarter of 2003 decreased to $5.0 million from $11.0 million in the first quarter of 2002. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $10.6 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." The loss before the cumulative effect was $4.8 million in the first three months of 2003, compared to income of $12.0 million for the same period of 2002. The lower results in the first quarter of 2003 reflected higher operating expenses -- primarily nuclear operating costs, purchased power costs and employee benefit costs. These higher costs were partially offset by additional revenues due to colder weather, increased sales revenues to FES, lower fuel costs and reduced financing costs, compared with the first quarter of 2002. Operating revenues increased by $4.0 million or 3.2% in the first quarter of 2003 compared with the same period in 2002. The higher revenues resulted from increased distribution deliveries due to colder temperatures and additional sales revenues to FES. Kilowatt-hour sales to retail customers were higher by 7.7% in the first quarter of 2003 from the same quarter of 2002, which increased generation sales revenue by $1.9 million. Electric generation services provided by alternative suppliers as a percent of total sales delivered in Penn's franchise area slightly increased by 0.9 percentage point in the first quarter of 2003 from the first quarter of 2002. Distribution deliveries increased 8.7% in the first quarter of 2003 compared with the corresponding quarter of 2002, with increases in all customer sectors (residential, commercial and industrial). This increased revenues from electricity throughput by approximately $0.9 million in the first quarter of 2003 from the same quarter of the prior years. Sales revenues from wholesale customers increased by $1.9 million (primarily to FES) in the first quarter of 2003 compared to the same quarter of 2002, due to higher market prices. Increased wholesale revenues occurred despite a reduction in kilowatt-hour sales in the first quarter of 2003 from the same quarter last year, due to a 34.3% reduction in available nuclear generation from Beaver Valley Unit 1 as a result of its refueling outage that began on March 8, 2003. Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the same quarter of 2002 are summarized in the following table:
Changes in Kilowatt-Hour Sales ----------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. 7.7% Wholesale............................... (21.0)% - --------------------------------------------------------- Total Electric Generation Sales........... (9.5)% ==================================================== Distribution Deliveries: Residential............................. 13.4% Commercial.............................. 6.7% Industrial.............................. 5.1% - -------------------------------------------------------- Total Distribution Deliveries............. 8.7% =================================================== 83
Operating Expenses and Taxes Total operating expenses and taxes increased by $21.0 million in the first quarter of 2003 from the first quarter of 2002. The following table presents changes from the prior year by expense category.
Operating Expenses and Taxes - Changes ------------------------------------------------------------------ Increase (Decrease) (In millions) Fuel............................................. $ (1.6) Purchased power costs............................ 4.1 Nuclear operating costs.......................... 24.6 Other operating costs............................ 6.6 -------------------------------------------------------------- Total operation and maintenance expenses....... 33.7 Provision for depreciation and amortization...... (1.0) General taxes.................................... 0.2 Income taxes..................................... (11.9) -------------------------------------------------------------- Total operating expenses and taxes............. $ 21.0 ============================================================== Lower fuel costs in the first quarter of 2003, compared with the same quarter of 2002, resulted from reduced nuclear generation. The increased purchased power costs reflected additional kilowatt-hour purchases and higher unit costs. Higher nuclear operating costs occurred in large part due to the refueling outage at Beaver Valley Unit 1 (65.00% ownership) in the first quarter of 2003 compared with refueling outage costs at Beaver Valley Unit 2 (13.74% ownership) in the first quarter of 2002. The increase in other operating costs reflects higher employee benefit costs and increased uncollectible customer accounts. Charges for depreciation and amortization decreased by $1.0 million in the first quarter of 2003 compared to the first quarter of 2002 primarily from lower charges resulting from the implementation of SFAS 143 ($0.3 million), including revised service life assumptions for generating plants ($0.3 million). Net Interest Charges Net interest charges continued to trend lower, decreasing by approximately $0.4 million in the first quarter of 2003 from the same period last year, reflecting redemptions and refinancings since the first quarter of 2002. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Penn recorded an after-tax credit to net income of $10.6 million. Penn identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $78 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $9 million. The asset retirement obligation (ARO) liability at the date of adoption was $121 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, Penn had recorded decommissioning liabilities of $120 million. Penn expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, it recognized a regulatory liability of $69 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for Penn. The remaining cumulative effect adjustment for unrecognized depreciation accretion offset by the reduction in the liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $18.2 million increase to income, or $10.6 million net of income taxes (see Note 5). Capital Resources and Liquidity - ------------------------------- Penn's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, Penn expects to meet its contractual obligations with cash from operations. Thereafter, Penn expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2003, Penn had $1.8 million of cash and cash equivalents, compared with $1.2 million as of December 31, 2002. The major sources for changes in these balances are summarized below. 84
Cash Flows From Operating Activities Cash flows provided from operating activities during the first quarter of 2003, compared with the corresponding period in 2002 were as follows: Operating Cash Flows 2003 2002 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $10 $ 28 Working capital and other............ 30 (21) ------------------------------------------------------------- Total................................ $40 $ 7 ============================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash from operating activities increased to $40 million in the first quarter of 2003 from $7 million in the same period of 2002. The increase in working capital and other primarily was due to a net change of $48 million due to higher accounts payable from associated companies in the first quarter of 2003 compared with corresponding amounts in the first quarter of 2002. A decrease in accounts receivable from associated companies also contributed $12 million to the increase in cash provided from working capital. The decrease in cash earnings in the first quarter of 2003 compared with the first quarter of 2002 primarily resulted from higher nuclear operating costs. Cash Flows From Financing Activities In the first quarter of 2003, net cash used for financing activities decreased to $14 million from $49 million in the same period last year. The decrease resulted from reduced long-term debt redemptions partially offset by increased dividends to OE. Penn had approximately $32.3 million of cash and temporary investments and no short-term indebtedness as of March 31, 2003. Penn may borrow from its affiliates on a short-term basis. Penn had the capability to issue $381 million of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests, Penn could issue up to $122 million of preferred stock (assuming no additional debt was issued) as of March 31, 2003. Cash Flows From Investing Activities Net cash flows used for investing activities totaled $26 million in the first quarter of 2003, compared to a net cash flows provided from investing activities of $44 million for the same period of 2002. The $70 million change to funds used for investing activities resulted from lower payments received on notes from associated companies and additional capital expenditures. In the first quarter of 2002, net cash flows provided from investing activities totaled $44 million, principally from payments on the sale of property to affiliates as part of corporate separation and the sale of transmission facilities to ATSI, partially offset by property additions. During the last three quarters of 2003, capital requirements for property additions and capital leases are expected to be about $41 million, including $5 million for nuclear fuel. Penn has additional requirements of approximately $42 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at 85
estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including Penn. On April 11, 2003 Moody's Investors Service affirmed its existing ratings for FirstEnergy. Moody's noted that the ratings were based on the stable business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for the EUOC, including the OE Companies. Moody's noted that merger debt had put pressure on FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all levels within the company although those plans had been delayed by external events. Equity Price Risk - ----------------- Included in Penn's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $43 million and $38 million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $4 million reduction in fair value as of March 31, 2003. Outlook - ------- Beginning in 1999, Penn's customers were able to select alternative energy suppliers and customer rates have been restructured into separate components to support customer choice. Currently, a number of customers previously electing to be served by alternative energy providers returned to the Penn system for their energy needs. Penn has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Penn continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Regulatory Matters Regulatory assets are costs which have been authorized by the Pennsylvania Public Utility Commission and the Federal Energy Regulatory Commission, for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets declined $79.1 million to $77.8 million on March 31, 2003 from the balance as of December 31, 2002, with $69.2 million of the decrease related to the cumulative entry adopting SFAS 143. All of Penn's regulatory assets are expected to continue to be recovered under the provisions of its regulatory plan. As part of Penn's transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. Penn's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. In 2003, the total peak load forecasted for customers electing to stay with Penn, including the load served by Penn's affiliate is 955 megawatts. Environmental Matters Penn believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements. Penn continues to evaluate its compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W.H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio, for which hearings began on February 3, 2003. The NOV and complaint allege violations of the Clean Air Act (CAA). The civil complaint against OE and Penn requests installation of "best available control technology" as well as civil penalties of up to $27,500 per day. Although unable to predict the outcome of these proceedings, OE and Penn believe the Sammis Plant is in full compliance with the CAA and that the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. The Sammis Plant continues to operate while these proceedings are pending. 86
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. Penn believes it is in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from its 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 Penn's Pennsylvania facilities by May 1, 2003. The effects of compliance on Penn with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect Penn's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Penn believes it is in material compliance with existing regulations, but are unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Significant Accounting Policies - ------------------------------- Penn 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 Penn's financial results. All of the 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 those specific factors. Penn's more significant accounting policies are described below. Regulatory Accounting Penn is subject to regulation that sets the prices (rates) they are permitted to charge its customers based on the costs that the 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. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded. As of March 31, 2003, Penn's regulatory assets totaled $78 million. 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 been 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 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 87
Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," Penn periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, Penn recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). 88
<TABLE> <CAPTION> JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended March 31, ------------------------- 2003 2002 -------- -------- (In thousands) <S> <C> <C> OPERATING REVENUES.............................................................. $656,952 $450,713 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 1,334 1,176 Purchased power.............................................................. 399,066 210,985 Other operating costs........................................................ 69,723 68,517 -------- -------- Total operation and maintenance expenses................................. 470,123 280,678 Provision for depreciation and amortization.................................. 60,167 63,903 General taxes................................................................ 15,812 17,003 Income taxes................................................................. 35,642 27,861 -------- -------- Total operating expenses and taxes....................................... 581,744 389,445 -------- -------- OPERATING INCOME................................................................ 75,208 61,268 OTHER INCOME.................................................................... 1,176 2,826 -------- -------- INCOME BEFORE NET INTEREST CHARGES.............................................. 76,384 64,094 -------- -------- NET INTEREST CHARGES: Interest on long-term debt................................................... 23,312 22,717 Allowance for borrowed funds used during construction........................ (123) (482) Deferred interest............................................................ (3,202) 449 Other interest expense (credit).............................................. (159) (1,244) Subsidiary's preferred stock dividend requirements........................... 2,674 2,675 -------- -------- Net interest charges..................................................... 22,502 24,115 -------- -------- NET INCOME...................................................................... 53,882 39,979 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 125 753 -------- -------- EARNINGS ON COMMON STOCK........................................................ $ 53,757 $ 39,226 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements. </FN> </TABLE> 89
<TABLE> <CAPTION> JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ---------- ---------- (In thousands) <S> <C> <C> ASSETS ------ UTILITY PLANT: In service................................................................ $3,572,958 $3,478,803 Less--Accumulated provision for depreciation.............................. 1,454,468 1,343,846 ---------- ---------- 2,118,490 2,134,957 Construction work in progress - electric plant............................ 26,191 20,687 ---------- ---------- 2,144,681 2,155,644 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 106,390 106,820 Nuclear fuel disposal trust............................................... 155,403 149,738 Long-term notes receivable from associated companies...................... 20,333 20,333 Other..................................................................... 22,206 18,202 ---------- ---------- 304,332 295,093 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 1,836 4,823 Receivables- Customers (less accumulated provisions of $4,620,000 and $4,509,000 respectively, for uncollectible accounts).............................. 228,123 247,624 Associated companies.................................................... 376 318 Other .................................................................. 19,789 20,134 Notes receivable from associated companies................................ 52,607 77,358 Materials and supplies, at average cost................................... 1,567 1,341 Prepayments and other..................................................... 21,675 37,719 ---------- ---------- 325,973 389,317 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 3,094,751 3,199,012 Goodwill.................................................................. 2,000,875 2,000,875 Other..................................................................... 15,644 12,814 ---------- ---------- 5,111,270 5,212,701 ---------- ---------- $7,886,256 $8,052,755 ========== ========== </TABLE> 90
<TABLE> <CAPTION> JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ----------- ------------ (In thousands) <S> <C> <C> CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: Common stockholder's equity- Common stock, $10 par value, authorized 16,000,000 shares - 15,371,270 shares outstanding......................................... $ 153,713 $ 153,713 Other paid-in capital................................................... 3,029,218 3,029,218 Accumulated other comprehensive loss.................................... (835) (865) Retained earnings....................................................... 56,760 92,003 ---------- ---------- Total common stockholder's equity................................... 3,238,856 3,274,069 Preferred stock not subject to mandatory redemption....................... 12,649 12,649 Company-obligated mandatorily redeemable preferred securities............. 125,243 125,244 Long-term debt............................................................ 1,204,713 1,210,446 ---------- ---------- 4,581,461 4,622,408 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 167,315 173,815 Accounts payable- Associated companies.................................................... 107,880 170,803 Other................................................................... 79,249 106,504 Accrued taxes............................................................. 58,908 13,844 Accrued interest.......................................................... 32,932 27,161 Other..................................................................... 105,934 112,408 ---------- ---------- 552,218 604,535 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 707,995 691,721 Accumulated deferred investment tax credits............................... 9,364 9,939 Power purchase contract loss liability.................................... 1,637,650 1,710,968 Nuclear fuel disposal costs............................................... 166,692 166,191 Asset retirement obligation............................................... 105,390 -- Nuclear plant decommissioning costs....................................... 5,212 135,355 Other..................................................................... 125,486 111,638 ---------- ---------- 2,752,577 2,825,812 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $7,886,256 $8,052,755 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these balance sheets. </FN> </TABLE> 91
<TABLE> <CAPTION> JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended March 31, 2003 2002 -------- -------- (In thousands) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................................... $ 53,882 $ 39,979 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........................... 60,167 63,903 Other amortization.................................................... 185 511 Deferred costs, net................................................... (35,082) (65,608) Deferred income taxes, net............................................ 14,977 8,678 Investment tax credits, net........................................... (575) (899) Receivables........................................................... 19,788 44,122 Materials and supplies................................................ (226) 6 Accounts payable...................................................... (90,178) (4,966) Prepayments and other................................................. 16,044 5,904 Accrued taxes......................................................... 45,064 34,570 Accrued interest...................................................... 5,771 4,353 Other................................................................. 6,034 1,837 -------- -------- Net cash provided from operating activities......................... 95,851 132,390 -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Redemptions and Repayments - Long-term debt.......................................................... (10,090) (50,000) Short-term borrowings, net.............................................. -- (18,149) Dividend Payments- Common stock............................................................ (89,000) -- Preferred stock......................................................... (125) (753) -------- -------- Net cash provided from (used for) financing activities.............. (99,215) (68,902) -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................ (24,323) (25,902) Capital trust investments................................................. -- (101) Notes receivable - associated companies, net.............................. 24,750 -- Other..................................................................... (50) (1,292) -------- -------- Net cash provided from (used for) investing activities.............. 377 (27,295) -------- -------- Net increase (decrease) in cash and cash equivalents......................... (2,987) 36,193 Cash and cash equivalents at beginning of period ............................ 4,823 31,424 -------- -------- Cash and cash equivalents at end of period................................... $ 1,836 $ 67,617 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements. </FN> </TABLE> 92
REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors 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 March 31, 2003, and the related consolidated statements of income and cash flows for the three-month periods ended March 31, 2003 and 2002. These interim 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 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. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003 93
JERSEY CENTRAL POWER & LIGHT COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. JCP&L provides regulated transmission and distribution services in northern, western and east central New Jersey. New Jersey customers are able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. JCP&L's regulatory plan required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Also under the regulatory plan, JCP&L continues to deliver power to homes and businesses through its existing distribution system and is required to maintain the "provider of last resort" (PLR) obligation known as Basic Generation Services (BGS) for customers who elect to retain JCP&L as their power supplier. Results of Operations - --------------------- Earnings on common stock in the first quarter of 2003 increased to $53.8 million from $39.2 million in the first quarter of 2002. Higher operating revenues primarily due to increases in wholesale sales and distribution deliveries were partially offset by higher purchased power costs. Operating revenues increased by $206.2 million or 45.8% in the first quarter of 2003 compared with the same period in 2002. The higher revenues resulted from higher wholesale revenues that increased by $139.2 million over the first quarter of 2002. JCP&L's BGS obligation was transferred to external parties through a February 2002 auction process authorized by the New Jersey Board of Public Utilities (NJBPU). The auction removed JCP&L's BGS obligation for the period from August 1, 2002 through July 31, 2003, and as a result, it has been selling all of its self-supplied energy (from non-utility generation power contracts and owned generation) into the wholesale market. The NJBPU subsequently approved the February 2003 BGS auction results for the period beginning August 1, 2003. Distribution deliveries increased 14.5% in the first quarter of 2003 from the corresponding quarter of 2002, increasing revenues from electricity throughput by $37.4 million. Distribution deliveries benefited from substantially higher residential and commercial demand, due in large part to colder temperatures, which was partially offset by a decrease in industrial demand. Changes in distribution deliveries in the first quarter of 2003 compared with the first quarter of 2002 are summarized in the following table:
Changes in Kilowatt-Hour Deliveries ------------------------------------------------------ Increase (Decrease) Residential........................... 17.6% Commercial............................ 18.1% Industrial............................ (2.4)% ------------------------------------------------------ Total Distribution Deliveries........... 14.5% ================================================= 94
Operating Expenses and Taxes Total operating expenses and taxes increased $192.3 million in the first quarter of 2003 compared with the first quarter of 2002, primarily due to increases in purchased power costs. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes ------------------------------------------------------------------ Increase (Decrease) (In millions) Fuel............................................. $ 0.1 Purchased power costs............................ 188.1 Other operating costs............................ 1.2 -------------------------------------------------------------- Total operation and maintenance expenses....... 189.4 Provision for depreciation and amortization...... (3.7) General taxes.................................... (1.2) Income taxes..................................... 7.8 -------------------------------------------------------------- Total operating expenses and taxes............. $192.3 =============================================================== Higher purchased power costs in the first quarter of 2003, compared to the same quarter of 2002, were due primarily to increased kilowatt-hour purchases through two-party agreements and reduced deferred energy and capacity costs. The decrease in depreciation and amortization charges of $3.7 million was due to the cessation of amortization of regulatory assets related to the previously divested Oyster Creek Nuclear Generating Station. Net Interest Charges Net interest charges decreased by $1.6 million in the first quarter of 2003 compared with the first quarter of 2002, primarily due to debt redemptions since the end of the first quarter of 2002. That decrease was partially offset by interest on $320 million of transition bonds issued in June 2002 (see Note 1). Capital Resources and Liquidity - ------------------------------- JCP&L's cash requirements in 2003 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities with affiliates will be used to manage working capital requirements. Over the next three years, JCP&L expects to meet its contractual obligations with cash from operations. Thereafter, JCP&L expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2003, JCP&L had $1.8 million of cash and cash equivalents, compared with $4.8 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash flows provided from the first quarter of 2003 and 2002 operating activities are as follows: Operating Cash Flows 2003 2002 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $93 $ 46 Working capital and other............ 3 86 ------------------------------------------------------------- Total................................ $96 $132 ============================================================= (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes and investment tax credits. Net cash from operating activities decreased to $96 million in the first quarter of 2003 from $132 million in the first quarter of 2002. This decrease was due to an $83 million increase in funds used for working capital and other, partially offset by a $47 million increase in cash earnings. The increase in working capital reflects a $85 million net decrease in accounts payable. The cash earnings increase was partially attributable to increased revenues from sales to the wholesale market in 2003. 95
Cash Flows From Financing Activities In the first quarter of 2003, net cash used for financing activities of $99 million primarily reflected the redemption of $10 million of secured long-term debt and $89 million of common stock dividend payments to FirstEnergy. In the first quarter of 2002, net cash used for financing activities totaled $69 million, primarily due to the redemption of debt. As of March 31, 2003, JCP&L had approximately $54.4 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 (FMB) other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of March 31, 2003. JCP&L had the capability to issue $426 million of additional senior notes based upon FMB collateral. Based upon applicable earnings coverage tests JCP&L could issue a total of $1.55 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2003. Cash Flows From Investing Activities Net cash provided from investing activities totaled $0.4 million in the first quarter of 2003, compared with net cash used of $27 million in the first quarter of 2002. Net cash provided from investing in 2003 represented loan repayments from associated companies offset by property additions. Net cash used in investing activities in 2002 were principally for property additions. During the last three quarters of 2003, capital requirements for property additions are expected to be about $87 million. JCP&L has additional requirements of approximately $164 million for maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including JCP&L. On April 11, 2003 Moody's Investors Service affirmed its existing ratings for FirstEnergy. Moody's noted that the ratings were based on the stable business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for the EUOC, including JCP&L. Moody's noted that merger debt had put pressure on FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all levels within the company although those plans had been delayed by external events. Market Risk Information - ----------------------- JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk 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, it uses a variety of non-derivative and derivative instruments, including forward contracts, options and future contracts. The derivatives are used for hedging purposes. Most of JCP&L's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2003 is summarized in the following table: 96
<TABLE> <CAPTION> Increase (Decrease) in the Fair Value of Commodity Derivative Contracts Non-Hedge Hedge Total - ------------------------------------------------------------------------------------------------ (In millions) <S> <C> <C> <C> Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2003................... $ 8.7 $(0.1) $ 8.6 New contract value when entered............................... -- -- -- Additions/Increase in value of existing contracts............. 4.1 0.1 4.2 Change in techniques/assumptions.............................. -- -- -- Settled contracts............................................. -- -- -- - ------------------------------------------------------------------------------------------------- Net Assets - Derivatives Contracts as of March 31, 2003 (1)... $12.8 $ -- $12.8 ================================================================================================= Impact of Changes in Commodity Derivative Contracts (2) Income Statement Effects (Pre-Tax)............................ $ -- $ -- $ -- Balance Sheet Effects: Other Comprehensive Income (Pre-Tax).......................... $ -- $ 0.1 $ 0.1 Regulatory Liability.......................................... $ 4.1 $ -- $ 4.1 <FN> (1) Includes $12.8 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. </FN> </TABLE> Derivatives included on the Consolidated Balance Sheet as of March 31, 2003: Non-Hedge Hedge Total --------------------------------------------------------------------- (In millions) Current- Other Assets...................... $ -- $ -- $ -- Non-Current- Other Deferred Charges............ 12.8 -- 12.8 --------------------------------------------------------------------- Net assets........................ $12.8 $ -- $12.8 ===================================================================== The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, 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 uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: <TABLE> <CAPTION> Source of Information - - Fair Value by Contract Year 2003(1) 2004 2005 2006 Thereafter Total - -------------------------------------------------------------------------------------------------------------- (In millions) <S> <C> <C> <C> <C> <C> <C> Prices based on external sources(1) $ .3 $2.0 $2.5 $ -- $ -- $ 4.8 Prices based on models -- -- -- 1.1 6.9 8.0 - ------------------------------------------------------------------------------------------------------------- Total(2) $ .3 $2.0 $2.5 $1.1 $6.9 $12.8 ============================================================================================================= <FN> (1) Broker quote sheets. (2) Includes $12.6 million from an embedded option that is offset by a regulatory liability and does not affect earnings. </FN> </TABLE> JCP&L 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 derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of March 31, 2003. Equity Price Risk Included in JCP&L's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $51 million and $52 million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of March 31, 2003. 97
Outlook - ------- Beginning in 1999, all of JCP&L's customers were able to select alternative energy suppliers. JCP&L continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. To support customer choice, rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs. Regulatory assets are costs which have been authorized by the NJBPU and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of JCP&L's regulatory assets are expected to continue to be recovered under the provisions of the regulatory proceedings discussed below. JCP&L's regulatory assets totaled $3.1 billion and $3.2 billion as of March 31, 2003 and December 31, 2002, respectively. Regulatory Matters Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L submitted two rate filings with the NJBPU in August 2002. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current market transition charge and societal benefits charge rates; one proposed method of recovery of these costs is the securitization of the deferred balance. Hearings began in February 2003. On March 18, 2003, a report prepared by independent auditors addressing costs deferred by JCP&L from August 1, 1999 through July 31, 2002, was transmitted to the Office of Administrative Law, where JCP&L's rate case is being heard. While the auditors concluded that JCP&L's energy procurement strategy and process was reasonable and prudent, they identified potential disallowances approximating $17 million. The report subjected $436 million of deferred costs to a retrospective prudence review during a period of extreme price uncertainty and volatility in the energy markets. Although JCP&L disagrees with the potential disallowances, it is pleased with the report's major conclusions and overall tone. Hearings began in February 2003. On March 18, 2003, a report prepared by independent auditors addressing costs deferred by JCP&L from August 1, 1999 through July 31, 2002, was transmitted to the Office of Administrative Law, where JCP&L's rate case is being heard. While the auditors concluded that JCP&L's energy procurement strategy and process was reasonable and prudent, they identified potential disallowances approximating $17 million. The report subjected $436 million of deferred costs to a retrospective prudence review during a period of extreme price uncertainty and volatility in the energy markets. Although JCP&L disagrees with the potential disallowances, it is pleased with the report's major conclusions and overall tone. Hearings concluded on April 28, 2003, and initial briefs were filed on May 7, 2003. The JCP&L brief supports its two rate filings requesting an aggregate rate increase of approximately $122 million in base electric rates and the recovery of deferred costs based on the securitization methodology discussed above. If the securitization methodology is not allowed, then JCP&L has requested deferred cost recovery over a four-year period with a return on the unamortized deferred cost balance. This alternative would increase the overall rate request to approximately $246 million. JCP&L strongly disagrees with many of the positions taken by NJBPU Staff. The Staff's position would result in a $119 million estimated annual earnings decrease related to the electricity delivery charge. In addition, the Staff recommended disallowing approximately $153 million of deferred energy costs which would result in a one-time pre-tax charge against earnings of $153 million. JCP&L will respond to the Staff's position in its Reply Brief which is due on May 21, 2003. The Administrative Law Judge's recommended decision is due by the end of June 2003 and the NJBPU's subsequent decision is due in July 2003. In 1997, the NJBPU authorized JCP&L to recover from customers, subject to possible refund, $135 million of costs incurred in connection with a 1996 buyout of a power purchase agreement. JCP&L has recovered the full $135 million; the NJBPU has established a procedural schedule to take further evidence with respect to the buyout to enable it to make a final prudence determination contemporaneously with the resolution of the pending rate case. In December 2001, the NJBPU authorized the auctioning of BGS for the period from August 1, 2002 through July 31, 2003 to meet the electricity demands of all customers who have not selected an alternative supplier. The results of the February 2002 auction, with the NJBPU's approval, removed JCP&L's BGS obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In February 2003, the auctioning of BGS for the period beginning August 1, 2003 took place. The auction covered a fixed price bid (applicable to all residential and smaller commercial and industrial customers) and an hourly price bid (applicable to all large industrial customers) process. JCP&L sells all self-supplied energy (from non-utility generation power contracts and owned generation) into the wholesale market with offsetting credits to its deferred energy cost balances. Environmental Matters JCP&L has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of 98
disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total costs of cleanup, JCP&L's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered through a non-bypassable societal benefits charge. JCP&L has accrued liabilities aggregating approximately $47.1 million as of March 31, 2003. JCP&L does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against us, the most significant of which are described above and below. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including JCP&L. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. In July 1999, two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court against JCP&L and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in its service territory. In May 2001, the court denied without prejudice JCP&L's motion seeking decertification of the class. Discovery continues in the class action, but no trial date has been set. In October 2001, the court held argument on the plaintiffs' motion for partial summary judgment, which contends that JCP&L is bound to several findings of the NJBPU investigation. The plaintiffs' motion was denied by the Court in November 2001 and the plaintiffs' motion to file an appeal of this decision was denied by the New Jersey Appellate Division. JCP&L has also filed a motion for partial summary judgment that is currently pending before the Superior Court. JCP&L is unable to predict the outcome of these matters. Significant Accounting Policies - ------------------------------- JCP&L prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of JCP&L's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. JCP&L's more significant accounting policies are described below. Purchase Accounting The merger between FirstEnergy and GPU 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 were finalized in the fourth quarter of 2002, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," JCP&L evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. The forecasts used in JCP&L's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on JCP&L's future evaluations of goodwill. As of March 31, 2002, JCP&L had recorded goodwill of approximately $2.0 billion related to the merger. Regulatory Accounting JCP&L is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine JCP&L is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in New Jersey, a significant amount of regulatory assets have been recorded. As of March 31, 2003, JCP&L's regulatory assets totaled $3.1 billion. 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. 99
Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. JCP&L continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of JCP&L's normal operations, it 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 been 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 distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. 100
Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," JCP&L periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, JCP&L recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Recently Issued Accounting Standards Not Yet Implemented FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (JCP&L's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. JCP&L currently has transactions with entities in connection with the sale of preferred securities and debt secured by bondable property, and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. JCP&L currently consolidates those entities and believes it will continue to consolidate following the adoption of FIN 46. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS133 for decisions made by the Derivative Implementation Group, as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for quarters which began prior to June 15, 2003, which continue to be applied based on their original effective dates. JCP&L is currently assessing the new standard and has not yet determined the impact on its financial statements. 101
<TABLE> <CAPTION> METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended March 31, ------------------------- 2003 2002 -------- -------- (In thousands) <S> <C> <C> OPERATING REVENUES.............................................................. $251,203 $245,790 -------- -------- OPERATING EXPENSES AND TAXES: Purchased power.............................................................. 143,461 136,140 Other operating costs........................................................ 32,512 29,005 -------- -------- Total operation and maintenance expenses................................. 175,973 165,145 Provision for depreciation and amortization.................................. 27,161 15,292 General taxes................................................................ 16,860 16,912 Income taxes................................................................. 7,198 14,871 -------- -------- Total operating expenses and taxes....................................... 227,192 212,220 -------- -------- OPERATING INCOME................................................................ 24,011 33,570 OTHER INCOME.................................................................... 5,168 5,131 -------- -------- INCOME BEFORE NET INTEREST CHARGES.............................................. 29,179 38,701 -------- -------- NET INTEREST CHARGES: Interest on long-term debt................................................... 10,539 10,455 Allowance for borrowed funds used during construction........................ (73) (284) Deferred interest............................................................ (440) (193) Other interest expense....................................................... 463 273 Subsidiary's preferred stock dividend requirements........................... 1,890 1,838 -------- -------- Net interest charges..................................................... 12,379 12,089 -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 16,800 26,612 Cumulative effect of accounting change (net of income taxes of $154,000) (Note 5) 217 -- -------- -------- NET INCOME...................................................................... $ 17,017 $ 26,612 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements. </FN> </TABLE> 102
<TABLE> <CAPTION> METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ----------- ------------ (In thousands) <S> <C> <C> ASSETS ------ UTILITY PLANT: In service................................................................ $1,815,666 $1,620,613 Less--Accumulated provision for depreciation.............................. 744,297 547,925 ---------- ---------- 1,071,369 1,072,688 Construction work in progress.............................................. 16,394 16,078 ---------- ---------- 1,087,763 1,088,766 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 156,015 155,690 Long-term notes receivable from associated companies...................... 12,418 12,418 Other..................................................................... 27,283 19,206 ---------- ---------- 195,716 187,314 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 212,571 15,685 Receivables- Customers (less accumulated provisions of $5,451,000 and $4,810,000 respectively, for uncollectible accounts)............................. 119,873 120,868 Associated companies.................................................... 5,609 23,219 Other................................................................... 18,496 18,235 Notes receivable from associated companies................................ 8,005 -- Material and supplies, at average cost.................................... 139 -- Prepayments and other..................................................... 39,871 9,731 ---------- ---------- 404,564 187,738 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 1,126,936 1,179,125 Goodwill.................................................................. 885,832 885,832 Other..................................................................... 37,631 36,030 ---------- ---------- 2,050,399 2,100,987 ---------- --------- $3,738,442 $3,564,805 ========== ========== </TABLE> 103
<TABLE> <CAPTION> METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ----------- ------------ (In thousands) <S> <C> <C> CAPITALIZATION AND LIABILITIES ------------------------------ CAPITALIZATION: Common stockholder's equity- Common stock, without par value, authorized 900,000 shares - 859,500 shares outstanding............................................ $1,297,784 $1,297,784 Accumulated other comprehensive loss.................................... (13) (39) Retained earnings....................................................... 34,857 17,841 ---------- ---------- Total common stockholder's equity................................... 1,332,628 1,315,586 Company-obligated trust preferred securities.............................. 92,461 92,409 Long-term debt............................................................ 646,932 538,790 ---------- ---------- 2,072,021 1,946,785 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 160,467 60,467 Accounts payable- Associated companies.................................................... 86,162 56,861 Other................................................................... 31,250 28,583 Notes payable to associated companies..................................... 65,212 88,299 Accrued taxes............................................................. 4,180 16,096 Accrued interest.......................................................... 11,650 16,448 Other..................................................................... 11,960 11,690 ---------- ---------- 370,881 278,444 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 324,698 316,757 Accumulated deferred investment tax credits............................... 12,313 12,518 Purchase power contract loss liability.................................... 650,947 660,507 Nuclear fuel disposal costs............................................... 37,655 37,541 Nuclear plant decommissioning costs....................................... -- 270,611 Asset retirement obligation............................................... 201,192 -- Other..................................................................... 68,735 41,642 ---------- ---------- 1,295,540 1,339,576 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $3,738,442 $3,564,805 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets. </FN> </TABLE> 104
<TABLE> <CAPTION> METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended March 31, 2003 2002 --------- -------- (In thousands) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................................... $ 17,017 $ 26,612 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........................... 27,161 15,292 Deferred costs, net................................................... (3,820) (6,920) Deferred income taxes, net............................................ 1,385 7,882 Investment tax credits, net........................................... (205) (212) Receivables........................................................... 18,344 12,914 Materials and supplies................................................ (139) -- Accounts payable...................................................... 31,968 (20,812) Cumulative effect of accounting change (Note 5)....................... (371) -- Accrued taxes......................................................... (11,916) (1,351) Accrued interest...................................................... (4,798) (6,833) Prepayments and other................................................. (30,140) (26,897) Other................................................................. (11,717) (17,188) -------- -------- Net cash provided from (used for) operating activities.............. 32,769 (17,513) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt.......................................................... 247,696 -- Short-term borrowings, net.............................................. -- 55,547 Redemptions and Repayments- Long-term debt.......................................................... (40,000) (30,000) Short-term borrowings, net.............................................. (23,087) -- -------- -------- Net cash provided from (used for) financing activities.............. 184,609 25,547 -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................ (10,333) (9,096) Notes receivable-associated companies, net................................ (2,371) (3,161) Other..................................................................... (7,788) (239) -------- -------- Net cash provided from (used for) investing activities.............. (20,492) (12,496) -------- -------- Net increase (decrease) in cash and cash equivalents......................... 196,886 (4,462) Cash and cash equivalents at beginning of period ............................ 15,685 25,274 -------- -------- Cash and cash equivalents at end of period................................... $212,571 $ 20,812 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements. </FN> </TABLE> 105
REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Metropolitan Edison Company: We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of March 31, 2003, and the related consolidated statements of income and cash flows for the three-month periods ended March 31, 2003 and 2002. These interim 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 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. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003 106
METROPOLITAN EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Met-Ed provides regulated transmission and distribution services in eastern and south central Pennsylvania. Pennsylvania customers are able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. Met-Ed's regulatory plan required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Met-Ed continues to deliver power to homes and businesses through its existing distribution system and maintains provider of last resort (PLR) obligations to customers who elect to retain Met-Ed as their power supplier. Results of Operations - --------------------- Net income in the first quarter of 2003 decreased to $17.0 million from $26.6 million in the first quarter of 2002. Net income in the first quarter of 2003 included an after-tax credit of $0.2 million from the cumulative effect of an accounting change due to the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $16.8 million in the first three months of 2003 compared with $26.6 million in the corresponding period of 2002. Higher operating expenses primarily due to increases in depreciation and amortization and purchased power costs were partially offset by higher distribution revenues. Electric Sales Operating revenues increased by $5.4 million, or 2.2% in the first quarter of 2003 compared with the same period of 2002. The higher revenues resulted from increased distribution deliveries to residential and commercial customers partially offset by lower wholesale kilowatt-hour sales. Distribution deliveries increased 9.9% in the first quarter of 2003 from the same quarter of the prior year, increasing revenues from electricity throughput by $8.9 million. Distribution deliveries benefited from higher residential and commercial demand, due in large part to colder temperatures, which was partially offset by a decrease in industrial demand from the continued effect of a sluggish economy. In the first quarter of 2003, more commercial and industrial customers chose an alternate power supplier compared with the same period of 2002, which held down the increase in retail generation kilowatt-hour sales. Generation kilowatt-hour sales increased 1.4% consisting of higher residential and commercial sales (22.9% and 4.9%, respectively) offset by a 35.8% decrease in industrial sales, partially reflecting the increased shopping by commercial and industrial customers. Wholesale sales revenues decreased $7.0 million principally due to a reduction in kilowatt-hour sales to affiliated companies. Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the same quarter of 2002 are summarized in the following table: Changes in Kilowatt-Hour Sales --------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. 1.4% Wholesale............................... (99.9)% ---------------------------------------------------- Total Electric Generation Sales........... (7.4)% ==================================================== Distribution Deliveries: Residential............................. 22.7% Commercial.............................. 11.3% Industrial.............................. (6.3)% --------------------------------------------------- Total Distribution Deliveries............. 9.9% =================================================== 107
Operating Expenses and Taxes Total operating expenses and taxes increased $15.0 million in the first quarter of 2003 from the first quarter of 2002, primarily due to increases in purchased power costs and depreciation and amortization charges. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes ------------------------------------------------------------------ Increase (Decrease) (In millions) Purchased power costs............................ 7.3 Other operating costs............................ 3.5 -------------------------------------------------------------- Total operation and maintenance expenses....... 10.8 Provision for depreciation and amortization...... 11.9 General taxes.................................... -- Income taxes..................................... (7.7) -------------------------------------------------------------- Total operating expenses and taxes............. $15.0 =============================================================== Higher purchased power costs in the first quarter of 2003, compared with the first quarter of 2002, were primarily due to higher average unit costs. The increase in depreciation and amortization charges of $11.9 million reflected an increase in amortization of regulatory assets being recovered through the competitive transition charge (CTC). Other operating costs increased by $3.5 million as a result of higher pension and other employee benefit costs, as well as increased uncollectible customer accounts and insurance expenses. Net Interest Charges Net interest charges increased by $0.3 million in the first quarter of 2003 compared with the first quarter of 2002. The increase reflects the issuance of $250 million of new senior notes in March 2003 that will be used for redeeming outstanding long-term debt later in 2003. Partially offsetting that increase was the redemption of $40 million of notes in the first quarter of 2003. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Met-Ed recorded an after-tax credit to net income of approximately $0.2 million. Met-Ed identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $186 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $186 million. The asset retirement obligation (ARO) liability at the date of adoption was $198 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, Met-Ed had recorded decommissioning liabilities of $260 million. Met-Ed expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, Met-Ed recognized a regulatory liability of $61 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the liabilities was a $0.4 million increase to income, or $0.2 million net of income taxes. Capital Resources and Liquidity - ------------------------------- Met-Ed's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and optional debt redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Over the next three years, Met-Ed expects to meet its contractual obligations with cash from operations. Thereafter, Met-Ed expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2003, Met-Ed had $212.6 million of cash and cash equivalents (principally to be used for the redemption of long-term debt in the second quarter of 2003) compared with $15.7 million as of December 31, 2002. The major sources for changes in these balances are summarized below. 108
Cash Flows From Operating Activities Cash flows provided from (used for) operating activities in the first quarter of 2003 and 2002 were as follows: Operating Cash Flows 2003 2002 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 41 $42 Working capital and other............ (8) (60) ------------------------------------------------------------- Total................................ $33 $(18) ============================================================= (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and major noncash credits. Net cash from operating activities increased to $33 million in the first quarter of 2003 compared with net cash used for operating activities in the first quarter of 2002 of $18 million. The increase was due to a $52 million increase in funds from working capital and other, primarily from changes in accounts payable. Cash Flows From Financing Activities In the first quarter of 2003, net cash provided from financing activities of $185 million reflected the issuance of $250 million of senior notes, partially offset by the redemption of $40 million of long-term debt and $23 million of short-term debt. In the first quarter of 2002, net cash provided from financing activities totaled $26 million, due to an increase in short-term debt, partially offset by the redemption of long-term debt. As of March 31, 2003, Met-Ed had approximately $220.6 million of cash and temporary investments and approximately $65.2 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 (FMB) other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of March 31, 2003, Met-Ed had the capability to issue $14 million of additional senior notes based upon FMB collateral. Met-Ed had no restrictions on the issuance of preferred stock. Cash Flows From Investing Activities Net cash flows used in investing activities totaled $20 million in the first quarter of 2003, compared to the same period of 2002. The net cash flows used for investing resulted from property additions and loans to associated companies. Expenditures for property additions primarily support Met-Ed's energy delivery operations. In the first quarter of 2002, net cash flows used in investing activities totaled $12 million, principally due to property additions. During the remaining quarters of 2003, capital requirements for property additions are expected to be about $42 million. Met-Ed has additional requirements of approximately $20 million for maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements; restricted cash as of March 31, 2003 was available for optional debt redemptions later in 2003. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including Met-Ed. 109
On April 11, 2003 Moody's Investors Service affirmed its existing ratings for FirstEnergy. Moody's noted that the ratings were based on the stable business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for the EUOC, including Met-Ed. Moody's noted that merger debt had put pressure on FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all levels within the company although those plans had been delayed by external events. Market Risk Information - ----------------------- Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk 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, it uses a variety of non-derivative and derivative instruments, including options and future contracts. The derivatives are used for hedging purposes. Most of Met-Ed's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2003 is summarized in the following table: <TABLE> <CAPTION> Increase (Decrease) in the Fair Value of Commodity Derivative Contracts Non-Hedge Hedge Total - ------------------------------------------------------------------------------------------------ (In millions) <S> <C> <C> <C> Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2003................... $17.4 $ 0.1 $17.5 New contract value when entered............................... -- -- -- Additions/Increase in value of existing contracts............. 8.2 -- 8.2 Change in techniques/assumptions.............................. -- -- -- Settled contracts............................................. -- (0.1) (0.1) - ------------------------------------------------------------------------------------------------- Net Assets - Derivatives Contracts as of March 31, 2003 (1)... $25.6 $ -- $25.6 ================================================================================================= Impact of Changes in Commodity Derivative Contracts (2) Income Statement Effects (Pre-Tax)............................ $ -- $ -- $ -- Balance Sheet Effects: Other Comprehensive Income (Pre-Tax).......................... $ -- $ 0.1 $ 0.1 Regulatory Liability.......................................... $ 8.2 $ -- $ 8.2 <FN> (1) Includes $25.6 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. </FN> </TABLE> Derivatives included on the Consolidated Balance Sheet as of March 31, 2003: Non-Hedge Hedge Total ---------------------------------------------------------------------- (In millions) Current- Other Assets...................... $-- $ -- $-- Non-Current- Other Deferred Charges............ 25.6 -- 25.6 --------------------------------------------------------------------- Net assets........................ $25.6 $ -- $25.6 ===================================================================== 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 uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: 110
<TABLE> <CAPTION> Source of Information - - Fair Value by Contract Year 2003 2004 2005 2006 Thereafter Total - -------------------------------------------------------------------------------------------------------------- (In millions) <S> <C> <C> <C> <C> <C> <C> Prices based on external sources(1) $.6 $4.0 $5.0 $ -- $ -- $ 9.6 Prices based on models -- -- -- 2.3 13.7 16.0 - -------------------------------------------------------------------------------------------------------------- Total(2) $.6 $4.0 $5.0 $2.3 $13.7 $25.6 ============================================================================================================== <FN> (1) Broker quote sheets. (2) Includes $25.1 million from an embedded option that is offset by a regulatory liability and does not affect earnings. </FN> </TABLE> Met-Ed 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 derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of March 31, 2003. Equity Price Risk Included in Met-Ed's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $79 million and $81 million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $8 million reduction in fair value as of March 31, 2003. Outlook - ------- Beginning in 1999, all of Met-Ed's customers were able to select alternative energy suppliers. Met-Ed continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. The Pennsylvania Public Utility Commission (PPUC) authorized Met-Ed's rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. Met-Ed has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as its PLR obligation. Regulatory assets are costs which have been authorized by the PPUC and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of Met-Ed's regulatory assets are expected to continue to be recovered under the provisions of the regulatory plan as discussed below. Met-Ed's regulatory assets totaled $1.1 billion and $1.2 billion as of March 31, 2003 and December 31, 2002, respectively. Regulatory Matters Effective September 1, 2002, Met-Ed assigned its PLR responsibility to its unregulated supply affiliate, FirstEnergy Solutions Corp. (FES), through a wholesale power sale agreement which expires in December 2003 and may be extended for each successive calendar year. Under the terms of the wholesale agreement, FES assumed the supply obligation, and the energy supply profit and loss risk, for the portion of power supply requirements that Met-Ed does not self-supply under its non-utility generation (NUG) contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces its exposure to high wholesale power prices by providing power at or below the shopping credit for its uncommitted PLR energy costs during the term of the agreement to FES. Met-Ed will continue to defer the cost differences between NUG contract rates and the rates reflected in its capped generation rates. On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the Commonwealth Court's decision which effectively affirmed the PPUC's order approving the merger between FirstEnergy and GPU, let stand the Commonwealth Court's denial of Met-Ed's PLR rate relief and remanded the merger savings issue back to the PPUC. On April 2, 2003, the PPUC remanded the merger savings issue to the Office of Administrative Law for hearings and directed Met-Ed to file a position paper on the effect of the Commonwealth Court's order on the Settlement Stipulation by May 2, 2003. Because Met-Ed had already reserved for the deferred energy costs and FES has largely hedged Met-Ed's anticipated PLR energy supply requirements through 2005, Met-Ed believes that the disallowance of CTC recovery of PLR costs above its capped generation rates will not have a future adverse financial impact during that period. 111
Environmental Matters Met-Ed has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total costs of cleanup, Met-Ed's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Met-Ed has accrued liabilities aggregating approximately $0.2 million as of March 31, 2003. Met-Ed does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against Met-Ed, the most significant of which are described above. Significant Accounting Policies - ------------------------------- Met-Ed prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect its financial results. All of its assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. Met-Ed's more significant accounting policies are described below. Purchase Accounting The merger between FirstEnergy and GPU 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 were finalized in the fourth quarter of 2002, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," Met-Ed evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. The forecasts used in Met-Ed's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of March 31, 2003, Met-Ed had recorded goodwill of approximately $885.8 million related to the merger. Regulatory Accounting Met-Ed is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine it 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. As of March 31, 2003, Met-Ed's regulatory assets totaled $1.1 billion. Met-Ed regularly reviews these assets to assess its 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. Met-Ed continually monitors its derivative contracts to 112
determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of Met-Ed's normal operations, it 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 been 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 distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," Met-Ed periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying 113
value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, Met-Ed would recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (Met-Ed's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. Met-Ed currently has transactions with entities in connection with the sale of preferred securities, which may fall within the scope of this interpretation, and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. Met-Ed currently consolidates these entities and believes it will continue to consolidate following the adoption of FIN 46. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS 133 for decisions made by the Derivative Implementation Group, as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective of quarters which began prior to June 15, 2003, which continue to be applied based on their original effective dates. Met-Ed is currently assessing the new standard and has not yet determined the impact on its financial statements. 114
<TABLE> <CAPTION> PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended March 31, ------------------------- 2003 2002 -------- -------- (In thousands) <S> <C> <C> OPERATING REVENUES.............................................................. $254,876 $242,820 -------- -------- OPERATING EXPENSES AND TAXES: Purchased power.............................................................. 173,236 138,129 Other operating costs........................................................ 36,551 33,800 -------- -------- Total operation and maintenance expenses................................. 209,787 171,929 Provision for depreciation and amortization.................................. 13,773 14,831 General taxes................................................................ 15,744 15,030 Income taxes................................................................. 2,893 12,499 -------- -------- Total operating expenses and taxes....................................... 242,197 214,289 -------- -------- OPERATING INCOME................................................................ 12,679 28,531 OTHER INCOME (EXPENSE).......................................................... (192) 298 -------- -------- INCOME BEFORE NET INTEREST CHARGES.............................................. 12,487 28,829 -------- -------- NET INTEREST CHARGES: Interest on long-term debt................................................... 7,339 8,421 Allowance for borrowed funds used during construction........................ (81) (120) Deferred interest............................................................ (996) (751) Other interest expense ...................................................... 143 605 Subsidiary's preferred stock dividend requirements........................... 1,888 1,835 -------- -------- Net interest charges..................................................... 8,293 9,990 -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 4,194 18,839 Cumulative effect of accounting change (net of income taxes of $777,000) (Note 5) ........................................................... 1,096 -- -------- -------- NET INCOME...................................................................... $ 5,290 $ 18,839 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these statements. </FN> </TABLE> 115
<TABLE> <CAPTION> PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ----------- ------------ (In thousands) <S> <C> <C> ASSETS ------ UTILITY PLANT: In service................................................................ $1,944,053 $1,844,999 Less--Accumulated provision for depreciation.............................. 752,152 647,581 ---------- ---------- 1,191,901 1,197,418 Construction work in progress- Electric plant.......................................................... 18,135 19,200 ---------- ---------- 1,210,036 1,216,618 OTHER PROPERTY AND INVESTMENTS: Non-utility generation trusts............................................. 6,370 109,881 Nuclear plant decommissioning trusts...................................... 87,925 88,818 Long-term notes receivable from associated companies...................... 15,515 15,515 Other..................................................................... 13,400 9,425 ---------- ---------- 123,210 223,639 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 310 10,310 Receivables- Customers (less accumulated provisions of $6,881,000 and $6,216,000 respectively, for uncollectible accounts)............................ 118,776 128,303 Associated companies.................................................... 40,143 45,236 Other................................................................... 25,364 16,184 Prepayments and other..................................................... 37,330 2,551 ---------- ---------- 221,923 202,584 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 543,699 599,663 Goodwill.................................................................. 898,086 898,086 Deferred income taxes..................................................... 30,138 1,517 Other..................................................................... 21,601 21,147 ---------- ---------- 1,493,524 1,520,413 ---------- ---------- $3,048,693 $3,163,254 ========== ========== </TABLE> 116
<TABLE> <CAPTION> PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) March 31, December 31, 2003 2002 ----------- ------------ (In thousands) <S> <C> <C> 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................................................... 1,215,256 1,215,256 Accumulated other comprehensive loss.................................... (61) (69) Retained earnings....................................................... 37,995 32,705 ---------- ---------- Total common stockholder's equity................................... 1,359,002 1,353,704 Company-obligated trust preferred securities ............................. 92,267 92,214 Long-term debt............................................................ 469,800 470,274 ---------- ---------- 1,921,069 1,916,192 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 827 813 Accounts payable- Associated companies.................................................... 137,152 129,906 Other................................................................... 31,110 29,690 Notes payable to associated companies..................................... -- 90,427 Accrued taxes............................................................. 48,556 21,271 Accrued interest.......................................................... 18,374 12,695 Other..................................................................... 8,522 8,409 ---------- ---------- 244,541 293,211 ---------- ---------- DEFERRED CREDITS: Accumulated deferred investment tax credits............................... 10,677 10,924 Nuclear plant decommissioning costs....................................... -- 135,450 Nuclear fuel disposal costs............................................... 18,827 18,771 Power purchase contract loss liability.................................... 727,220 765,063 Asset retirement obligation............................................... 100,596 -- Other..................................................................... 25,763 23,643 ---------- ---------- 883,073 953,851 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $3,048,693 $3,163,254 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these balance sheets. </FN> </TABLE> 117
<TABLE> <CAPTION> PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended March 31, --------------------------- 2003 2002 -------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: <S> <C> <C> Net income .................................................................. $ 5,290 $ 18,839 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........................... 13,773 14,831 Other amortization.................................................... (14) 782 Deferred costs, net................................................... (92) (18,434) Deferred income taxes, net............................................ (41,640) (6,304) Investment tax credits, net........................................... (247) (285) Receivables........................................................... 5,440 11,803 Accounts payable...................................................... 8,666 (11,822) Cumulative effect of accounting change (Note 5)....................... (1,873) -- Accrued taxes......................................................... 27,284 15,262 Accrued interest...................................................... 5,679 6,089 Prepayments and other................................................. (34,778) (28,844) Other, net............................................................ (7,076) (6,692) -------- -------- Net cash provided from (used for) operating activities.............. (19,588) (4,775) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Redemptions and Repayments- Short-term borrowings, net.............................................. (90,427) (39,573) -------- -------- Net cash used for (provided from) financing activities.................... (90,427) (39,573) -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................ (6,312) (10,194) Proceeds from non-utility generation trusts............................... 106,327 34,208 Other, net................................................................ -- (239) -------- -------- Net cash used for (provided from) investing activities.............. 100,015 23,775 -------- -------- Net decrease in cash and cash equivalents.................................... (10,000) (20,573) Cash and cash equivalents at beginning of period ............................ 10,310 39,033 -------- -------- Cash and cash equivalents at end of period................................... $ 310 $ 18,460 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these statements. </FN> </TABLE> 118
REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Pennsylvania Electric Company: We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of March 31, 2003, and the related consolidated statements of income and cash flows for the three-month periods ended March 31, 2003 and 2002. These interim 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 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. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 9, 2003 119
PENNSYLVANIA ELECTRIC COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements based on information currently available to management that is subject to certain risks and uncertainties. Such statements typically contain, but are not limited to, the terms anticipate, potential, expect, believe, estimate and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Penelec provides regulated transmission and distribution services in northern, western and south central Pennsylvania. Pennsylvania customers are able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. Penelec's regulatory plan required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Penelec continues to deliver power to homes and businesses through its existing distribution system and maintains provider of last resort (PLR) obligations to customers who elect to retain Penelec as their power supplier. Results from Operations - ----------------------- Net income in the first quarter of 2003 decreased to $5.3 million from $18.8 million in the first quarter of 2002. Net income in the first quarter of 2003 included an after-tax credit of $1.1 million from the cumulative effect of an accounting change due to the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $4.2 million in the first three months of 2003 compared with $18.8 million for the corresponding period of 2002. Higher operating expenses, primarily due to purchased power costs, were partially offset by higher operating revenues. Electric Sales Operating revenues increased by $12.1 million or 5.0% in the first quarter of 2003 compared with the same period in 2002. The higher revenues resulted from higher distribution deliveries to residential and commercial customers which were partially offset by lower industrial kilowatt-hour sales. Distribution deliveries increased 6.7% in the first quarter of 2003 from the same quarter of the prior year, increasing revenues from electricity throughput by $7.1 million. Distribution deliveries benefited from higher residential and commercial demand, due in large part to colder temperatures, which was partially offset by a decrease in industrial demand from the continued effect of a sluggish economy. Penelec's generation kilowatt-hour sales increase of 2.7% reflected higher residential and commercial sales (17.3% and 9.9%, respectively) offset by a 19.3% decrease in industrial sales growth. The substantial decrease in industrial sales was primarily due to more industrial customers being served by alternative suppliers in the first quarter of 2003 compared to the same period of 2002. Retail generation sales revenue increases of $4.3 million were partially offset by a decrease in wholesale sales revenues of $0.7 million. Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the first quarter of 2002 are summarized in the following table: Changes in Kilowatt-Hour Sales -------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ 2.7% Wholesale............................. (109.7)% -------------------------------------------------- Total Electric Generation Sales......... (0.3)% ================================================== Distribution Deliveries: Residential........................... 17.2% Commercial............................ 11.0% Industrial............................ (6.5)% ------------------------------------------------- Total Distribution Deliveries........... 6.7% ================================================= 120
Operating Expenses and Taxes Total operating expenses and taxes increased $27.9 million or 13.0% in the first quarter of 2003 from the first quarter of 2002, primarily due to increases in purchased power costs. The following table presents changes during the first quarter of 2003 from the same period in 2002 for operating expenses and taxes. Operating Expenses and Taxes - Changes - ----------------------------------------------------------------- Increase (Decrease) (In millions) Purchased power costs............................ 35.1 Other operating costs............................ 2.8 - -------------------------------------------------------------- Total operation and maintenance expenses....... 37.9 Provision for depreciation and amortization...... (1.1) General taxes.................................... 0.7 Income taxes..................................... (9.6) - --------------------------------------------------------------- Total operating expenses and taxes............. $27.9 ============================================================== Higher purchased power costs in the first quarter of 2003, compared with the same quarter of 2002, were due to higher average unit costs and increased kilowatt-hour purchases to meet greater retail generation sales requirements. The increase in other operating costs is primarily due to higher pension and other employee benefit costs and uncollectible customer accounts. Net Interest Charges Net interest charges decreased by $1.7 million in the first quarter of 2003 compared with the first quarter of 2002, reflecting debt redemptions since the end of the first quarter of 2002. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Penelec recorded an after-tax credit to net income of $1.1 million. Penelec identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $93 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $93 million. The asset retirement obligation (ARO) liability at the date of adoption was $99 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, Penelec had recorded decommissioning liabilities of $130 million. Penelec expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, Penelec recognized a regulatory liability of $29 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the liabilities was a $1.9 million increase to income, or the $1.1 million net of income taxes. Capital Resources and Liquidity - ------------------------------- Penelec's cash requirements in 2003 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without increasing its net debt and preferred stock outstanding. Over the next three years, Penelec expects to meet its contractual obligations with cash from operations. Thereafter, Penelec expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2003, Penelec had $0.3 million of cash and cash equivalents, compared with $10.3 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Net cash used for operating activities was $20 million in the first quarter of 2003 and $5 million in the first quarter of 2002. Cash flows used by operating activities in the first quarter of 2003 and 2002 were as follows: 121
Operating Cash Flows 2003 2002 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ (25) $ 9 Working capital and other............ 5 (14) ------------------------------------------------------------- Total................................ $(20) $ (5) ============================================================= (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and major noncash credits. Net cash used for operating activities increased to $20 million in the first quarter of 2003 from $5 million in the same period of 2002. This increase was due to the decrease of cash earnings primarily resulting from higher purchased power costs. Cash Flows From Financing Activities Net cash used for financing activities of $90 million and $40 million in the first quarter of 2003 and the first quarter of 2002, respectively, represents the redemptions of short-term debt. As of March 31, 2003, Penelec had about $0.3 million of cash and no short-term indebtedness. Penelec may borrow from its affiliates on a short-term basis. Penelec will not issue first mortgage bonds (FMB) other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of March 31, 2003, Penelec had the capability to issue $3 million of additional senior notes based upon FMB collateral. Penelec had no restrictions on the issuance of preferred stock. Cash Flows From Investing Activities Net cash flows provided from investing activities totaled $100 million in the first quarter of 2003, compared with $24 million in the same period of 2002. The net cash flows provided from investing activities resulted from proceeds from nonutility generation trusts, slightly offset by property additions in both periods. Expenditures for property additions primarily support Penelec's energy delivery operations. During the remaining quarters of 2003, capital requirements for property additions are expected to be about $43 million. Penelec has additional requirements of approximately $221 million for maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including Penelec. On April 11, 2003 Moody's Investors Service affirmed its existing ratings for FirstEnergy. Moody's noted that the ratings were based on the stable business of FirstEnergy's EUOC. Moody's also affirmed its existing ratings for the EUOC, including Penelec. Moody's noted that merger debt had put pressure on FirstEnergy's rating, but that FirstEnergy had plans to reduce debt at all levels within the company although those plans had been delayed by external events. Market Risk Information - ----------------------- Penelec uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an 122
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, it uses a variety of non-derivative and derivative instruments, including options and future contracts. The derivatives are used for hedging purposes. Most of Penelec's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2003 is summarized in the following table: <TABLE> <CAPTION> Increase (Decrease) in the Fair Value of Commodity Derivative Contracts Non-Hedge Hedge Total - ------------------------------------------------------------------------------------------------ (In millions) <S> <C> <C> <C> Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2003................... $ 8.7 $ 0.1 $ 8.8 New contract value when entered............................... -- -- -- Additions/Increase in value of existing contracts............. 4.1 -- 4.1 Change in techniques/assumptions.............................. -- -- -- Settled contracts............................................. -- (0.1) (0.1) - ------------------------------------------------------------------------------------------------- Net Assets - Derivatives Contracts as of March 31, 2003 (1)... $12.8 $ -- $ 12.8 ================================================================================================= Impact of Changes in Commodity Derivative Contracts (2) Income Statement Effects (Pre-Tax)............................ $ .2 $ -- $ .2 Balance Sheet Effects: Other Comprehensive Income (Pre-Tax).......................... $ -- $(0.1) $ (0.1) Regulatory Liability.......................................... $ 3.9 $ -- $ 3.9 <FN> (1) Includes $12.8 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. </FN> </TABLE> Derivatives included on the Consolidated Balance Sheet as of March 31, 2003: Non-Hedge Hedge Total ---------------------------------------------------------------------- (In millions) Current- Other Assets...................... $ -- $ -- $ -- Non-Current- Other Deferred Charges............ 12.8 -- 12.8 --------------------------------------------------------------------- Net assets........................ $12.8 $ -- $12.8 ===================================================================== The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: <TABLE> <CAPTION> Source of Information - - Fair Value by Contract Year 2003 2004 2005 2006 Thereafter Total - ------------------------------------------------------------------------------------------------------------ (In millions) <S> <C> <C> <C> <C> <C> <C> Prices based on external sources(1) $ .2 $2.0 $2.5 $ -- $ -- $ 4.7 Prices based on models -- -- -- 1.2 6.9 8.1 - ----------------------------------------------------------------------------------------------------------- Total(2) $ .2 $2.0 $2.5 $1.2 $6.9 $12.8 =========================================================================================================== <FN> (1) Broker quote sheets. (2) Includes $12.6 million from an embedded option that is offset by a regulatory liability and does not affect earnings. </FN> </TABLE> Penelec 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 derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of March 31, 2003. 123
Equity Price Risk Included in Penelec's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $41 million and $42 million as of March 31, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $4 million reduction in fair value as of March 31, 2003. Outlook - ------- Beginning in 1999, all of Penelec's customers were able to select alternative energy suppliers. Penelec continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. The Pennsylvania Public Utility Commission (PPUC) authorized Penelec's rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a competitive transition charge (CTC). Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. Penelec has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as its PLR obligation. Regulatory assets are costs which have been authorized by the PPUC and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of Penelec's regulatory assets are expected to continue to be recovered under the provisions of the regulatory plan as discussed below. Penelec's regulatory assets totaled $544 million and $600 million as of March 31, 2003 and December 31, 2002, respectively. Regulatory Matters Effective September 1, 2002, Penelec assigned its provider of last resort (PLR) responsibility obligation to its unregulated supply affiliate, FirstEnergy Solutions Corp. (FES), through a wholesale power sale agreement which expires in December 2003 and may be extended for each successive calendar year. Under the terms of the wholesale agreement, FES assumed the supply obligation, and the energy supply profit and loss risk, for the portion of power supply requirements that Penelec does not self-supply under its non-utility generation (NUG) contracts and other existing power contracts with nonaffiliated third party suppliers. This arrangement reduces its exposure to high wholesale power prices by providing power at or below the shopping credit for its uncommitted PLR energy costs during the term of the agreement to FES. Penelec will continue to defer those cost differences between NUG contract rates and the rates reflected in its capped generation rates. On January 17, 2003, the Pennsylvania Supreme Court denied further appeals of the Commonwealth Court's decision which effectively affirmed the PPUC's order approving the merger between FirstEnergy and GPU, let stand the Commonwealth Court's denial of Penelec's PLR rate relief and remanded the merger savings issue back to the PPUC. On April 2, 2003, the PPUC remanded the merger savings issue to the Office of Administrative Law for hearings and directed Penelec to file a position paper on the effect of the Commonwealth Court's order on the Settlement Stipulation by May 2, 2003. Because Penelec had already reserved for the deferred energy costs and FES has largely hedged Penelec's anticipated PLR energy supply requirements through 2005, Penelec believes that the disallowance of CTC recovery of PLR costs above its capped generation rates will not have a future adverse financial impact during that period. Environmental Matters Penelec has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total costs of cleanup, Penelec's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Penelec has total accrued liabilities aggregating approximately $0.3 million as of March 31, 2003. Penelec does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Legal Matters Various lawsuits, claims and proceedings related to Penelec's normal business operations are pending against it, the most significant of which are described above. 124
Significant Accounting Policies - ------------------------------- Penelec prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect its financial results. All of its assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. Penelec's more significant accounting policies are described below. Purchase Accounting The merger between FirstEnergy and GPU 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 were finalized in the fourth quarter of 2002, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," Penelec evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. The forecasts used in its evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on Penelec's future evaluations of goodwill. As of March 31, 2003, Penelec had recorded goodwill of approximately $898.1 million related to the merger. Regulatory Accounting Penelec is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine it 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. As of March 31, 2003, Penelec's regulatory assets totaled $544 million. 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. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. Penelec continually monitors its derivative contracts to determine if Penelec's activities, expectations, intentions, assumptions and estimates remain valid. As part of Penelec's normal operations, it 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 been 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 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 125
Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets have earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," Penelec periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, Penelec would recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Recently Issued Accounting Standards Not Yet Implemented - -------------------------------------------------------- FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after 126
January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (Penelec's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. Penelec currently has involvement with entities in connection with the sale of preferred securities, which may fall within the scope of this interpretation, and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. Penelec currently consolidates these entities and believes it will continue to consolidate following the adoption of FIN 46. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS 133 for decisions made by the Derivative Implementation Group, as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for quarters which began prior to June 15, 2003, which continue to be applied based on their original effect dates. Penelec is currently assessing the new standard and has not yet determined the impact on its financial statements. 127
Controls and Procedures - ----------------------- (a) Evaluation of Disclosure Controls and Procedures The respective registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and 15d-14(c), as of a date within 90 days prior to the filing date of this report (Evaluation Date). Based on that evaluation those officers have concluded that the registrant's disclosure controls and procedures are effective and were designed to bring to their attention, during the period in which this quarterly report was being prepared, material information relating to the registrant and its consolidated subsidiaries by others within those entities. (b) Changes in Internal Controls There have been no significant changes in internal controls or in other factors that could significantly affect those controls subsequent to the Evaluation Date. 128
PART II. OTHER INFORMATION - --------------------------- Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits Exhibit Number ------ Met-Ed ------ 12 Fixed charge ratios 99.1 Certification letter from chief executive officer 99.2 Certification letter from chief financial officer Penelec ------- 12 Fixed charge ratios 15 Letter from independent public accountants 99.1 Certification letter from chief executive officer 99.2 Certification letter from chief financial officer JCP&L ----- 12 Fixed charge ratios 15 Letter from independent public accountants 99.2 Certification letter from chief financial officer 99.3 Certification letter from chief executive officer FirstEnergy, OE and Penn ------------------------ 15 Letter from independent public accountants 99.1 Certification letter from chief executive officer 99.2 Certification letter from chief financial officer CEI and TE ---------- 99.1 Certification letter from chief executive officer 99.2 Certification letter from chief financial officer Pursuant to reporting requirements of respective financings, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q. FirstEnergy, OE, CEI, TE and Penn do not have similar financing reporting requirements and have not filed their respective fixed charge ratios. Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of their respective total assets of FirstEnergy and its subsidiaries on a consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec but hereby agree to furnish to the Commission on request any such documents. (b) Reports on Form 8-K FirstEnergy- ------------ FirstEnergy filed ten reports on Form 8-K since December 31, 2002. A report dated January 17, 2003 reported updated information related with efforts to prepare Davis-Besse for a safe and reliable return to service and the updated schedule for JCP&L rate proceedings. A report dated January 21, 2003 reported that the Pennsylvania Supreme Court denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the Pennsylvania Public Utility Commission's order approving the FirstEnergy and GPU merger, let stand the Commonwealth Court's denial of PLR relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. A report dated March 11, 2003 reported updated Davis-Besse information including the installation of the new reactor head on the reactor vessel. A report dated March 17, 2003 reported updated Davis-Besse information, the filing of a $2 billion shelf registration with the SEC and the status of the JCP&L rate proceedings. A report dated March 18, 2003 reported NJBPU audit results of JCP&L restructuring-related deferrals. A report dated April 16, 2003 reported updated Davis-Besse information. A report dated April 18, 2003 reported FirstEnergy's divestiture of its Argentina operations through the abandonment of its investment resulting in a second quarter 2003 charge to net income of $63 129
million. A report dated May 1, 2003 reported FirstEnergy's first quarter 2003 results and other updated information including Davis-Besse updated ready for restart schedule. A report dated May 9, 2003 reported updated Davis-Besse information and a JCP&L rate proceedings update. A report dated May 9, 2003 reported that FirstEnergy had amended its Form 10-K for the year ended December 31, 2002 for a change in classification of a $57.1 net of tax charge with no effect on previously reported net income. OE, Penn- --------- None. CEI --- CEI filed six reports on Form 8-K since December 31, 2002. A report dated January 17, 2003 reported updated information related with efforts to prepare Davis-Besse for a safe and reliable return to service. A report dated March 11, 2003 reported updated Davis-Besse information including the installation of the new reactor head on the reactor vessel. A report dated March 17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003 reported Davis-Besse information. A report dated May 1, 2003 reported an updated Davis-Besse ready for restart schedules. A report dated May 9, 2003 reported updated Davis-Besse information. TE -- TE filed six reports on Form 8-K since December 31, 2002. A report dated January 17, 2003 reported updated information related with efforts to prepare Davis-Besse for a safe and reliable return to service. A report dated March 11, 2003 reported updated Davis-Besse information including the installation of the new reactor head on the reactor vessel. A report dated March 17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003 reported Davis-Besse information. A report dated May 1, 2003 reported an updated Davis-Besse ready for restart schedules. A report dated May 9, 2003 reported updated Davis-Besse information. Met-Ed ------ Met-Ed filed two reports on Form 8-K since December 31, 2002. A report dated January 21, 2003 reported that the Pennsylvania Supreme Court denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the Pennsylvania Public Utility Commission's order approving the FirstEnergy and GPU merger, let stand the Commonwealth Court's denial of PLR relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. A report dated March 12, 2003 reported Met-Ed's unaudited financial information for the year ended December 31, 2002. Penelec ------- Penelec filed one report on Form 8-K since December 31, 2002. A report dated January 21, 2003 reported that the Pennsylvania Supreme Court denied further appeals of the February 21, 2002 Pennsylvania Commonwealth Court decision, which effectively affirmed the Pennsylvania Public Utility Commission's order approving the FirstEnergy and GPU merger, let stand the Commonwealth Court's denial of PLR relief for Met-Ed and Penelec and remanded the merger savings issue back to the PPUC. JCP&L ----- JCP&L filed four reports on Form 8-K since December 31, 2002. A report dated January 17, 2003 reported the updated schedule for JCP&L rate proceedings. A report dated March 17, 2003 reported the status of the JCP&L rate proceedings. A report dated March 18, 2003 reported NJBPU audit results of JCP&L restructuring-related deferrals. A report dated May 9, 2003 reported a JCP&L rate proceedings update. 130
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. May 13, 2003 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 131
Certification I, H. Peter Burg, certify that: 1. I have reviewed this quarterly report on Form 10-Q of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Metropolitan Edison Company and Pennsylvania Electric Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this quarterly report; 4. Each registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for such registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to such registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of such registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. Each registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to such registrant's auditors and the audit committee of such registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect such registrant's ability to record, process, summarize and report financial data and have identified for such registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in such registrant's internal controls; and 6. Each registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 9, 2003 /s/H. Peter Burg --------------------------- H. Peter Burg Chief Executive Officer 132
Certification I, Earl T. Carey, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Jersey Central Power & Light Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 9, 2003 /s/Earl T. Carey -------------------------- Earl T. Carey Chief Executive Officer 133
Certification I, Richard H. Marsh, certify that: 1. I have reviewed this quarterly report on Form 10-Q of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this quarterly report; 4. Each registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for such registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to such registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of such registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. Each registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to such registrant's auditors and the audit committee of such registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect such registrant's ability to record, process, summarize and report financial data and have identified for such registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in such registrant's internal controls; and 6. Each registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 9, 2003 /s/Richard H. Marsh --------------------------------- Richard H. Marsh Chief Financial Officer 134