10-Q 1 fe_10-q.txt QUARTER ENDED MARCH 31, 2004 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-Q (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, 2004 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 ( ) FirstEnergy Corp. Yes ( ) No (X ) 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 Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: OUTSTANDING CLASS AS OF MAY 7, 2004 ----- ----------------- FirstEnergy Corp., $.10 par value 329,836,276 Ohio Edison Company, no par value 100 The Cleveland Electric Illuminating Company, no par value 79,590,689 The Toledo Edison Company, $5 par value 39,133,887 Pennsylvania Power Company, $30 par value 6,290,000 Jersey Central Power & Light Company, $10 par value 15,371,270 Metropolitan Edison Company, no par value 859,500 Pennsylvania Electric Company, $20 par value 5,290,596 FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company common stock. Ohio Edison Company is the sole holder of Pennsylvania Power Company common stock. This combined Form 10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy Corp. 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, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), adverse regulatory or legal decisions and the outcome of governmental investigations (including revocation of necessary licenses or operating permits), availability and cost of capital, the continuing availability and operation of generating units, the inability to accomplish or realize anticipated benefits of strategic goals, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities markets, further investigation into the causes of the August 14, 2003, regional power outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to that outage, a denial of or material change to FirstEnergy's Application related to its Rate Stabilization Plan, the risks and other factors discussed from time to time in the registrants' Securities and Exchange Commission filings, including their annual report on Form 10-K for the year ended December 31, 2003 and other similar factors. The registrants expressly disclaim any current intention to update any forward-looking statements contained in this document as a result of new information, future events, or otherwise. TABLE OF CONTENTS Pages Glossary of Terms......................................... i - ii Part I. Financial Information Items 1 and 2 Financial Statements and Management's Discussion and Analysis of Results of Operation and Financial Condition Notes to Consolidated Financial Statements................ 1-19 FirstEnergy Corp. Consolidated Statements of Income......................... 20 Consolidated Balance Sheets............................... 21 Consolidated Statements of Cash Flows..................... 22 Report of Independent Accountants......................... 23 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 24-48 Ohio Edison Company Consolidated Statements of Income......................... 49 Consolidated Balance Sheets............................... 50 Consolidated Statements of Cash Flows..................... 51 Report of Independent Accountants......................... 52 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 53-62 The Cleveland Electric Illuminating Company Consolidated Statements of Income......................... 63 Consolidated Balance Sheets............................... 64 Consolidated Statements of Cash Flows..................... 65 Report of Independent Accountants......................... 66 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 67-76 The Toledo Edison Company Consolidated Statements of Income......................... 77 Consolidated Balance Sheets............................... 78 Consolidated Statements of Cash Flows..................... 79 Report of Independent Accountants......................... 80 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 81-90 Pennsylvania Power Company Consolidated Statements of Income......................... 91 Consolidated Balance Sheets............................... 92 Consolidated Statements of Cash Flows..................... 93 Report of Independent Accountants......................... 94 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 95-101 TABLE OF CONTENTS (Cont'd) Pages Jersey Central Power & Light Company Consolidated Statements of Income......................... 102 Consolidated Balance Sheets............................... 103 Consolidated Statements of Cash Flows..................... 104 Report of Independent Accountants......................... 105 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 106-114 Metropolitan Edison Company Consolidated Statements of Income......................... 115 Consolidated Balance Sheets............................... 116 Consolidated Statements of Cash Flows..................... 117 Report of Independent Accountants......................... 118 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 119-127 Pennsylvania Electric Company Consolidated Statements of Income......................... 128 Consolidated Balance Sheets............................... 129 Consolidated Statements of Cash Flows..................... 130 Report of Independent Accountants......................... 131 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 132-141 Item 3. Quantitative and Qualitative Disclosure About Market Risk................................ 142 Item 4. Controls and Procedures............................ 142 Part II Other Information Item 1. Legal Proceedings.................................. 143 Item 6. Exhibits and Reports on Form 8-K................... 143 GLOSSARY OF TERMS The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its subsidiaries: ATSI.....................American Transmission Systems, Inc., owns and operates transmission facilities Avon.....................Avon Energy Partners Holdings CEI......................The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary CFC......................Centerior Funding Corporation, a wholly owned finance subsidiary of CEI Emdersa................ Empresa Distribuidora Electrica Regional S.A EUOC.....................Electric Utility Operating Companies, (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, ATSI) FENOC....................FirstEnergy Nuclear Operating Company, operates nuclear generating facilities FES......................FirstEnergy Solutions Corp., provides energy-related products and services FESC.....................FirstEnergy Service Company, provides legal, financial, and other corporate support services FGCO.....................FirstEnergy Generation Corp., operates nonnuclear generating facilities FirstCom.................First Communications, LLC, provides local and long- distance phone service FirstEnergy..............FirstEnergy Corp., a registered public utility holding company FSG......................FirstEnergy Facilities Services Group, LLC, the parent company of several heating, ventilation air conditioning and energy management companies GLEP.....................Great Lakes Energy Partners, LLC, an oil and natural gas exploration and production venture GPU......................GPU, Inc., former parent of Jersey Central Power & Light Copany, Metropolitan Edison Company and Pennsylvania Electric Company, which merged with FirstEnergy on November 7, 2001 GPU Capital..............GPU Capital, Inc., owned and operated electric distribution systems in foreign countries GPU Power................GPU Power, Inc., owned and operated generation facilities in foreign countries GPUS.....................GPU Service Company, previously provided corporate support services JCP&L....................Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary JCP&L Transition.........JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds MARBEL...................MARBEL Energy Corporation, holds FirstEnergy's interest in Great Lakes Energy Partners, LLC Met-Ed...................Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary MYR......................MYR Group, Inc., a utility infrastructure construction service company NEO......................Northeast Ohio Natural Gas Corp., a MARBEL subsidiary OE.......................Ohio Edison Company, an Ohio electric utility operating subsidiary OE Companies.............OE and Pennsylvania Power Company Penelec..................Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary Penn.....................Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary PNBV.....................PNBV Capital Trust, a special purpose entity created by OE in 1996 Shippingport.............Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997 The following abbreviations and acronyms are used to identify frequently used terms in this report: TE.......................The Toledo Edison Company, an Ohio electric utility operating subsidiary TECC.....................Toledo Edison Capital Corporation, a 90% owned subsidiary of TE ALJ......................Administrative Law Judge AOCL.....................Accumulated Other Comprehensive Loss APB......................Accounting Principles Board APB 25...................APB No. 25, "Accounting for Stock Issued to Employees" ARO......................Asset Retirement Obligation BGS......................Basic Generation Service CO2......................Carbon Dioxide CTC......................Competitive Transition Charge ECAR.....................East Central Area Reliability Agreement EITF.....................Emerging Issues Task Force EITF 03-6................EITF Issue No. 03-6, "Participating Securities and the Two-Class Method Under Financial Accounting Standards Board Statement No. 128, Earnings per Share" EITF 99-19...............EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" EPA......................Environmental Protection Agency FASB.....................Financial Accounting Standards Board FASB Concepts No. 7......FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements" FERC.....................Federal Energy Regulatory Commission FIN .....................FASB Interpretation FIN 46R..................FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" FSP......................FASB Staff Position i FSP 106-1................FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related to the Medicare" Prescription Drug, Improvement and Modernization Act of 2003" GAAP.....................Accounting Principles Generally Accepted in the United States IRS......................Internal Revenue Service ISO......................Independent System Operator KWH......................Kilowatt-hours LOC......................Letter of Credit Medicare Act.............Medicare Prescription Drug, Improvement and Modernization Act of 2003 MISO.....................Midwest Independent System Operator, Inc. Moody's..................Moody's Investors Service MTC......................Market Transition Charge MW.......................Megawatts NAAQS....................National Ambient Air Quality Standards NERC.....................North American Electric Reliability Council NJBPU....................New Jersey Board of Public Utilities NOX......................Nitrogen Oxides NRC......................Nuclear Regulatory Commission NUG......................Non-Utility Generation OCI......................Other Comprehensive Income OPEB.....................Other Post-Employment Benefits PJM......................PJM Interconnection ISO PLR......................Provider of Last Resort PPUC.....................Pennsylvania Public Utility Commission PRP......................Potentially Responsible Party PUCO.....................Public Utilities Commission of Ohio S&P......................Standard & Poor's SBC......................Societal Benefits Charge SEC......................Securities and Exchange Commission SFAS.....................Statement of Financial Accounting Standards SFAS 71..................SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" SFAS 87..................SFAS No. 87, "Employers' Accounting for Pensions" SFAS 106.................SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 123.................SFAS No. 123, "Accounting for Stock-Based Compensation" SFAS 133.................SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" SFAS 140.................SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities" SFAS 142.................SFAS No. 142, "Goodwill and Other Intangible Assets" SFAS 143.................SFAS No. 143, "Accounting for Asset Retirement Obligations" SFAS 144.................SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" SFAS 150.................SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" SO2......................Sulfur Dioxide SPE......................Special Purpose Entity TBC......................Transition Bond Charge TEBSA....................Termobarranquilla S.A., Empresa de Servicios Publicos TMI-2....................Three Mile Island Unit 2 VIE......................Variable Interest Entity ii 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 AND SUBSIDIARY JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES METROPOLITAN EDISON COMPANY AND SUBSIDIARIES PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1 - ORGANIZATION AND BASIS OF PRESENTATION: The principal business of FirstEnergy is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and 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, 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: FENOC, FES and its subsidiary FGCO, FESC, FirstCom, FSG, GPU Capital, GPU Power, MARBEL and MYR. The Companies follow the accounting policies and practices prescribed by the SEC, PUCO, PPUC, NJBPU and FERC. The condensed consolidated 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. Certain prior year amounts have been reclassified to conform with the current year presentation. In particular, expenses (including transmission and congestion charges) were reclassified among purchased power, other operating costs and depreciation and amortization to conform with the current year presentation of generation commodity costs. In addition, revenues, expenses and taxes related to certain divestitures in 2003 have been reclassified and reported net in discontinued operations (see Note 2). These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2003 for FirstEnergy and the Companies. The preparation of financial statements in conformity with GAAP 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. FirstEnergy's and the Companies' independent accountants have performed reviews of, and issued reports on, these consolidated interim financial statements in accordance with standards established by the American Institute of Certified Public Accountants. Pursuant to Rule 436(c) under the Securities Act of 1933, their reports of those reviews should not be considered a report within the meaning of Section 7 and 11 of that Act, and the independent accountant's liability under Section 11 does not extend to them. 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Consolidation FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest and VIE's for which FirstEnergy or any of its subsidiaries is the primary beneficiary. Intercompany transactions and balances are eliminated in consolidation. Investments in nonconsolidated affiliates (20-50 percent owned companies, joint ventures and partnerships) over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control, are accounted for on the equity basis. 1 FIN 46R addresses the consolidation of VIEs, including SPEs, that are not controlled through voting interests or in which the equity investors do not bear the residual economic risks and rewards. The first step under FIN 46R is to determine whether an entity is within the scope of FIN 46R which occurs if it is deemed to be a VIE. FirstEnergy and its subsidiaries consolidate those VIEs for which they have determined that they are the primary beneficiary as defined by FIN 46R. The provisions of FIN 46R were effective immediately for transactions entered into subsequent to January 31, 2003 and became effective no later than December 31, 2003 for entities that were considered SPEs under previous guidance, and no later than March 31, 2004 for all other entities. See Variable Interest Entities below. Variable Interest Entities Included in FirstEnergy's consolidated financial statements are PNBV and Shippingport, two VIEs created in 1996 and 1997, respectively, to refinance debt in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively. PNBV was established to purchase a portion of the lease obligation bonds issued with OE's 1987 sale and leaseback transactions involving its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent equity interest by a nonaffiliated third party and a three-percent equity interest held by OES Ventures, a wholly owned subsidiary of OE. Consolidation of PNBV by FirstEnergy and OE as of December 31, 2003 changed the trust investment of $361 million to an investment in collateralized lease bonds of $372 million. The $11 million increase represented the minority interest in the total assets of PNBV. Shippingport was established to purchase all of the lease obligation bonds issued by the owner trusts in CEI's and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE acquired all of the notes issued by Shippingport. Consolidation of this entity had no impact on the financial statements of FirstEnergy. Prior to the adoption of FIN 46R, the assets and liabilities of Shippingport were included on a proportionate basis in the financial statements of CEI and TE. Adoption of FIN 46R resulted in the consolidation of Shippingport by CEI as of December 31, 2003. Shippingport's note payable to TE of $199 million ($10 million current) and $208 million ($9 million current) as of March 31, 2004 and December 31, 2003, respectively, is included in long-term debt on CEI's Consolidated Balance Sheets. Through its investment in PNBV, OE has, and through their investments in Shippingport, CEI and TE have, variable interests in certain owner trusts that acquired the interests in the Perry Plant and Beaver Valley Unit 2, in the case of OE, and the Bruce Mansfield Plant, in the case of CEI and TE. FirstEnergy concluded that OE, CEI and TE were not the primary beneficiaries of the relevant owner trusts and were therefore not required to consolidate these entities. The leases are accounted for as operating leases in accordance with GAAP. The combined purchase price of $3.1 billion for all of the interests acquired by the owner trusts in 1987 was funded with debt of $2.5 billion and equity of $600 million. Each of OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale - leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $706 million, $109 million and $595 million, respectively, that would not be payable if the casualty value payments are made. As of March 31, 2004, CEI and TE have recorded above-market lease obligations related to the Bruce Mansfield Plant and Beaver Valley Unit 2 totaling $1.1 billion (CEI - $774 million and TE - $311 million), of which $85 million (CEI - $60 million and TE - $25 million) is current. CEI formed a wholly owned statutory business trust to sell preferred securities and invest the gross proceeds in 9% subordinated debentures of CEI. The sole assets of the trust are the subordinated debentures with an aggregate principal amount of $103 million. The trust's preferred securities are redeemable at 100% of their principal amount at CEI's option beginning in December 2006. CEI has effectively provided a full and unconditional guarantee of the trust's obligations under the preferred securities. Met-Ed and Penelec each formed statutory business trusts for substantially similar transactions to those of CEI. However, ownership of the respective Met-Ed and Penelec trusts is through separate wholly owned limited partnerships. The sole assets 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 million each) of Met-Ed and Penelec, respectively. The trust's preferred securities are redeemable at 100% of their principal amount at the option of Met-Ed and Penelec beginning in May 2004 and September 2004, respectively. In each case, Met-Ed and Penelec have effectively provided a full and unconditional guarantee of obligations under the trust's preferred securities. Met-Ed has provided notice to holders of the trust preferred securities that it intends to redeem such securities in May 2004. 2 Upon adoption of FIN 46R, the limited partnerships and statutory business trusts discussed above were no longer consolidated on the financial statements of FirstEnergy or, as applicable, CEI, Met-Ed or Penelec. As of December 31, 2003 and March 31, 2004, subordinated debentures held by the affiliated trusts were included in long-term debt of the applicable company and equity investments in the trusts were included in other investments. For the quarter ended March 31, 2004, FirstEnergy evaluated, among other entities, its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to an EUOC and the contract price for power is correlated with the plant's variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were structured pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of and has no equity or debt invested in these entities. FirstEnergy has determined that for all but nine of these entities, either JCP&L, Met-Ed or Penelec do not have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining nine entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. FirstEnergy has requested but not received the information necessary to determine whether these nine entities are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. Purchased power costs from these entities during the first quarters of 2004 and 2003 were $51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec - $7 million) and $56 million (JCP&L - $34 million, Met-Ed - $15 million and Penelec - $7 million), respectively. FirstEnergy is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. Earnings Per Share Basic earnings per share are computed using the weighted average of actual common shares outstanding as the denominator. Diluted earnings per share reflect the weighted average of actual common shares outstanding plus the potential additional common shares that could result if dilutive securities and agreements were exercised in the denominator. In the first quarter of 2004 and 2003, stock-based awards to purchase shares of common stock totaling 3.3 million and 3.6 million, respectively, were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. The following table reconciles the denominators for basic and diluted earnings per share from Income before Discontinued Operations and Cumulative Effect of Accounting Change: Three Months Ended March 31, Reconciliation of Basic and -------------------- Diluted Earnings per Share 2004 2003 --------------------------------------------------------------------------- (In thousands) Income before discontinued operations and cumulative effect of accounting change............ $173,999 $114,380 Average Shares of Common Stock Outstanding: Denominator for basic earnings per share (weighted average shares actually outstanding)... 327,057 293,886 Assumed exercise of dilutive stock options and awards....................................... 1,977 991 Denominator for diluted earnings per share.......... 329,034 294,877 =========================================================================== Income before Discontinued Operations and Cumulative Effect of Accounting Change, per common share: Basic............................................. $0.53 $0.39 Diluted........................................... $0.53 $0.39 --------------------------------------------------------------------------- Preferred Stock Subject to Mandatory Redemption Long-term debt includes the preferred stock of consolidated subsidiaries subject to mandatory redemption as of March 31, 2004 and December 31, 2003 in accordance with SFAS 150. This standard, issued in May 2003, establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity; certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. The adoption of SFAS 150 effective July 1, 2003 had no impact on FirstEnergy's Consolidated Statements of Income because the preferred dividends were previously included in net interest charges and required no reclassification. CEI and Penn, however, did not include the 3 preferred dividends on their manditorily redeemable preferred stock in interest expense for the quarter ended March 31, 2003, but have included the dividends in interest charges for the quarter ended March 31, 2004. Securitized Transition Bonds The consolidated financial statements of FirstEnergy and JCP&L include the financial statements of JCP&L Transition, a wholly owned limited liability company of JCP&L. In June 2002, JCP&L Transition 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 did not purchase and does not own any of the transition bonds, which are included as long-term debt on each of FirstEnergy's and JCP&L's Consolidated Balance Sheets. The transition bonds represent obligations only of JCP&L Transition and are collateralized solely by the equity and assets of JCP&L Transition, which consist primarily of bondable transition property. The bondable transition property is solely the property of JCP&L Transition. Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L sold the bondable transition property to JCP&L Transition and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreement with JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of $100,000 that is payable from TBC collections. Derivative Accounting FirstEnergy is exposed to financial risks resulting from fluctuating 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, the ineffective portion of hedge gains and losses is included in net income. In 2001, FirstEnergy entered into interest rate derivative transactions 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 are 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 net deferred loss included in AOCL as of March 31, 2004 and December 31, 2003 was $111 million. Approximately $6 million (after tax) of the net deferred loss on derivative instruments in AOCL as of March 31, 2004, is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will fluctuate from period to period based on various market factors. During the first quarter of 2004, FirstEnergy executed fixed-for-floating interest rate swap agreements with an aggregate notional amount of $200 million, whereby FirstEnergy receives fixed cash flows based on the fixed coupons of the hedged securities and pays variable cash flows based on short-term variable market interest rates. 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, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. FirstEnergy entered into interest rate swap agreements on $200 million notional amount of its subsidiaries' senior notes and subordinated debentures having a weighted average fixed interest rate of 5.73%; the interest rate swap agreements have effectively converted that rate to a current weighted average variable rate of 2.33%. The notional values of interest rate swap agreements increased to $1.35 billion as of March 31, 2004 from $1.15 billion as of December 31, 2003. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates 4 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), the goodwill is tested for impairment. If an impairment is indicated, FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. As of March 31, 2004, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. In the first quarter of 2004, FirstEnergy adjusted goodwill for interest received on a pre-merger income tax refund related to the former GPU companies. A summary of the changes in FirstEnergy's goodwill for the three months ended March 31, 2004 is shown below: (In millions) ------------------------------------------------------ Balance as of December 31, 2003 ........ $6,128 GPU acquisition......................... (11) ------ Balance as of March 31, 2004............ $6,117 ====== 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, 2004, FirstEnergy's AOCL was approximately $344 million as compared to the December 31, 2003 balance of $353 million. A reconciliation of net income to comprehensive income for the three months ended March 31, 2004 and 2003, is shown below: Three Months Ended March 31, ------------------- 2004 2003 ---- ---- (In thousands) Net income............................. $173,999 $218,502 Other comprehensive income, net of tax: Change in fair value of hedge transactions (393) 4,341 Unrealized gains on available for sale securities 9,215 1,484 -------- -------- Comprehensive income................... $182,821 $224,327 ======== ======== Asset Retirement Obligations FirstEnergy recognizes a liability for retirement obligations associated with tangible assets in accordance with SFAS 143. The Companies recognize a regulatory asset or liability when the criteria for such treatment are met. FirstEnergy has identified applicable legal obligations as defined under the 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. The ARO liability was $1.198 billion as of March 31, 2004 and included $1.185 billion for nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry, and TMI-2 nuclear generating facilities. The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy utilized an expected cash flow approach (as discussed in FASB Concepts No. 7) to measure the fair value of the nuclear decommissioning ARO. The Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of March 31, 2004, the fair value of the decommissioning trust assets was $1.420 billion. Under the current terms of the plants' operating licenses, payments for decommissioning of the nuclear generating units would begin in 2014, when actual decommissioning work would begin. The following table provides the beginning and ending aggregate carrying amount of the total ARO and the changes to the balance during the first quarter of 2004. ARO Reconciliation 2004 ---------------------------------------------------------------------------- (In millions) Beginning balance as of January 1, 2004 ...................... $1,179 Liabilities incurred.......................................... -- Liabilities settled........................................... -- Accretion in 2004............................................. 19 Revisions in estimated cash flows............................. -- ------------------------------------------------------------------------ Ending balance as of March 31, 2004........................... $1,198 ------------------------------------------------------------------------ 5 Stock-Based Compensation FirstEnergy applies the recognition and measurement principles of APB 25 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. In March 2004, the FASB issued an exposure draft of a proposed standard that, if adopted, will change the accounting for employee stock options and other equity-based compensation. The proposed standard would require companies to expense the fair value of stock options on the grant date and would be effective for the Companies on January 1, 2005. FirstEnergy will evaluate the requirements of the final standard, expected by late 2004, to determine the impact on its results of operations. If FirstEnergy had accounted for employee stock options under the fair value method, as provided under SFAS 123, 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 reductions to net income and earnings per share. The following table summarizes those effects. Three Months Ended March 31, ------------------ 2004 2003 ---- ---- (In thousands) Net income, as reported................... $173,999 $218,502 Add back stock-based compensation expense reported in net income, net of tax (based on APB 25)....................... -- 43 Deduct stock-based compensation expense based upon estimated fair value, net of tax (4,404) (2,983) --------------------------------------------------------------------- Adjusted net income....................... $169,595 $215,562 --------------------------------------------------------------------- Earnings Per Share of Common Stock - Basic As Reported.......................... $0.53 $0.74 Adjusted............................. $0.52 $0.73 Diluted As Reported.......................... $0.53 $0.74 Adjusted............................. $0.52 $0.73 Discontinued Operations FirstEnergy's discontinued operations in the first quarter of 2003 consisted of the net results aggregating $2 million from its Argentina and Bolivia international businesses and certain domestic operations divested in 2003. The related revenues, expenses and taxes were reclassified from the previously reported Consolidated Statement of Income for the quarter ended March 31, 2003 and netted in Discontinued Operations. In April 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. FirstEnergy sold its Bolivia operations, Empresa Guaracachi S.A., in December 2003. Domestic operations sold in 2003 consisted of three former FSG subsidiaries and the MARBEL subsidiary, NEO. Cumulative Effect of Accounting Change 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 on the date of adoption was $1.11 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. The remaining cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $175 million increase to income, $102 million net of tax, or $0.35 per share of common stock (basic and diluted) in the quarter ended March 31, 2003. 6 Restatements of TE and JCP&L Previously Reported Quarterly Results Earnings for the first quarter of 2003 have been restated for TE and JCP&L to reflect adjustments to costs that were subsequently capitalized to construction projects. The results for TE have also been restated to correct the amount reported for interest expense. TE's costs which were originally recorded as operating expenses and were subsequently capitalized to construction were $0.4 million ($0.2 million after-tax) in the first quarter of 2003. TE's interest expense was overstated by $0.9 million ($0.5 million after-tax) in the first quarter of 2003. Similar to TE, JCP&L's capital costs originally recorded as operating expenses were $0.2 million ($0.1 million after-tax) in the first quarter of 2003. The impact of these adjustments was not material to the consolidated balance sheets or consolidated statements of cash flows for TE and JCP&L for any quarter of 2003. The effects of these adjustments on the consolidated statements of income previously reported for TE and JCP&L for the three months ended March 31, 2003, are as follows:
TE JCP&L ---------------------------- ---------------------------- As Previously As As Previously As Reported Restated Reported Restated ------------- ----------- ------------- ------------ (In thousands) Operating Revenues..........................$ 231,822 $ 231,822 $ 656,952 $ 656,952 Operating Expenses.......................... 226,345 226,501 581,744 581,609 ----------- ------------ ---------- ----------- Operating Income............................ 5,477 5,321 75,208 75,343 Other income................................ 3,100 3,100 1,176 1,176 ----------- ------------ ---------- ----------- Income before net interest charges.......... 8,577 8,421 76,384 76,519 Net interest charges........................ 9,977 9,050 22,502 22,502 ----------- ------------ ---------- ----------- Income (loss) before cumulative effect of accounting change..................... (1,400) (629) 53,882 54,017 Cumulative effect of accounting change...... 25,550 25,550 -- -- ----------- ------------ ---------- ----------- Net income.................................. 24,150 24,921 53,882 54,017 Preferred stock dividend requirements....... 2,205 2,205 125 125 ----------- ------------ ---------- ----------- Earnings attributable to common stock.............................$ 21,945 $ 22,716 $ 53,757 $ 53,892 =========== ============ ========== ===========
3 - COMMITMENTS, GUARANTEES AND CONTINGENCIES: Capital Expenditures FirstEnergy's current forecast reflects expenditures of approximately $2.3 billion (OE-$295 million, CEI-$275 million, TE-$141 million, Penn-$143 million, JCP&L-$446 million, Met-Ed-$168 million, Penelec-$198 million, ATSI-$66 million, FES-$443 million and other subsidiaries-$125 million) for property additions and improvements from 2004-2006, of which approximately $720 million (OE-$111 million, CEI-$95 million, TE-$49 million, Penn-$63 million, JCP&L-$150 million, Met-Ed-$55 million, Penelec-$65 million, ATSI-$23 million, FES-$71 million and other subsidiaries-$38 million) is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $315 million (OE-$45 million, CEI-$62 million, TE-$44 million, Penn-$35 million and FES-$129 million), of which approximately $86 million (OE-$26 million, CEI-$27 million, TE-$12 million and Penn-$21 million) applies to 2004. 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. As of March 31, 2004, outstanding guarantees and other assurances aggregated $1.9 billion and included contract guarantees ($1 billion), surety bonds ($0.2 billion) and letters of credit ($.7 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 $1 billion (included in the $1.9 billion discussed above) as of March 31, 2004 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. 7 While guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or "material adverse event" the immediate payment of cash collateral or provision of an LOC may be required. The following table summarizes collateral provisions as of March 31, 2004: Collateral Paid Total -------------------------- Remaining Collateral Provisions Exposure Cash Letters of Credit Exposure(1) -------------------------------------------------------------------------------- (In millions) Rating downgrade.......... $228 $133 $18 $ 77 Adverse event............. 232 -- 69 163 ---------------------------------------------------------------------------- Total..................... $460 $133 $87 $240 ============================================================================ (1) As of April 12, 2004, FirstEnergy's remaining exposure was $237 million, with $141 million of cash and $72 million of letters of credit provided as collateral. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $240 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. FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project in Colombia, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has provided the TEBSA project lenders a $60 million letter of credit, which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. This letter of credit granted FirstEnergy the ability to sell its remaining 20.1% interest in Avon (parent of Midlands Electricity in the United Kingdom). Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. 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 that 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. Overall, FirstEnergy believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $91 million for 2004 through 2006, which is included in the $2.3 billion of forecasted capital expenditures for 2004 through 2006. Additional estimated capital expenditures of $481 million relating to proposed environmental laws could be required after 2006. Clean Air Act Compliance The Companies are required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies are complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments 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' 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 (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets. New Jersey and Pennsylvania submitted a SIP that required compliance with the NOx budgets at the Companies' New Jersey and Pennsylvania facilities by May 1, 2003. Michigan and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Michigan and Ohio facilities by May 31, 2004. The Companies' facilities have complied with the NOx budgets in 2003 and 2004, respectively. 8 National Ambient Air Quality Standards In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NOx and SO2 emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO2 emissions would be reduced by approximately 3.6 million tons in 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities. Mercury Emissions In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as "maximum achievable control technologies" (MACT) based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year. The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial. W. H. Sammis Plant 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, which is owned by OE and Penn. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. 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. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of March 31, 2004. Regulation of Hazardous Waste 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 subsequently determined 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 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, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2004, based on estimates of the total 9 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 SBC. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $65 million (JCP&L - $45.5 million, CEI - $2.4 million, TE - $0.2 million, Met-Ed - $0.05 million, Penelec - $0.02 million, and other - $16.8 million) as of March 31, 2004. The Companies accrue environmental liabilities only when they can conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in the Companies' determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Climate Change In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the U.S. Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18% through 2012. The Companies cannot currently estimate the financial impact of climate change policies although the potential restrictions on CO2 emissions could require significant capital and other expenditures. However, the CO2 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which includes low or non-CO2 emitting gas-fired and nuclear generators. Clean Water Act Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to the Companies' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority. Power Outages In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory. Since July 1999, this litigation has involved a substantial amount of legal discovery including interrogatories, request for production of documents, preservation and inspection of evidence, and depositions of the named plaintiffs and many JCP&L employees. In addition, there have been many motions filed and argued by the parties involving issues such as the primary jurisdiction and findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class decertification, and the damages claimed by the plaintiffs. In January 2000, the NJ Appellate Division determined that the trial court has proper jurisdiction over this litigation. In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict products liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings have been appealed to the Appellation Division and oral argument is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of March 31, 2004. On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. -Canada Power System Outage Task Force released its final report on this outage. The final report supercedes the interim report that had been issued in November, 2003. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including, an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide 10 effective diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has undertaken several initiatives, some prior to and some since the August 14th power outage, to enhance reliability which are consistent with these and other recommendations and believes it will complete those relating to summer 2004 by June 30 (see Regulatory Matters below). As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of March 31, 2004 for any expenditures in excess of those actually incurred through that date. Davis-Besse FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse plant. FirstEnergy is unable to predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002. Further, a petition was filed with the NRC on March 29, 2004 by a group objecting to the NRC's restart order of the Davis-Besse Nuclear Power Station. The Petition seeks among other things, suspension of the Davis-Besse operating license. If it were ultimately determined that FirstEnergy has legal liability or is otherwise made subject to enforcement action based on any of the above matters with respect to the Davis-Besse outage, it could have a material adverse effect on FirstEnergy's financial condition and results of operations. Other Legal Matters Various lawsuits, claims and proceedings related to FirstEnergy's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant not otherwise discussed above are described below. Legal proceedings have been filed against FirstEnergy in connection with, among other things, the restatements in August 2003, by FirstEnergy and its Ohio utility subsidiaries of previously reported results, the August 14th power outage described above, and the extended outage at the Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the issues raised include alleged violations of federal securities laws, breaches of fiduciary duties under state law by FirstEnergy directors and officers, and damages as a result of one or more of the noted events. The securities cases have been consolidated into one action pending in federal court in Akron, Ohio. The derivative actions filed in federal court likewise have been consolidated as a separate matter, also in federal court in Akron. There also are pending derivative actions in state court. FirstEnergy's Ohio utility subsidiaries were also named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14th power outage. FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against them. Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. If FirstEnergy were ultimately determined to have legal liability in connection with the legal proceedings described above, it could have a material adverse effect on its financial condition and results of operations. 11 4 - PENSION AND OTHER POSTRETIREMENT BENEFITS: The components of net periodic pension and postretirement benefit cost consisted of the following:
Pension Benefits Other Benefits -------------------- ------------------ Three months ended Three months ended March 31, March 31, -------------------- ------------------ 2004 2003 2004 2003 ------------------------------------------------------------------------------------------ (In millions) Service cost ............................. $ 19 $ 17 $ 10 $ 11 Interest cost............................. 63 64 30 35 Expected return on plan assets............ (71) (63) (11) (11) Transition obligation..................... -- -- -- 2 Amortization of prior service cost........ 2 2 (9) (2) Recognized net actuarial loss............. 10 16 10 11 ------ ------ ------ ------ Net periodic cost......................... $ 23 $ 36 $ 30 $ 46 ====== ====== ====== ======
FirstEnergy contributed $16 million to its other postretirement benefit plans in the first quarter of 2004 and has no funding requirements for the remainder of 2004. FirstEnergy did not contribute to its pension plans during the first quarter of 2004 and has no funding requirements for the remainder of 2004. The net periodic pension cost in the three months ended March 31, 2004 and March 31, 2003 included $3 million and $5 million, respectively, of costs capitalized. Similarly, the net periodic cost for other postretirement costs in the three months ended March 31, 2004 and March 31, 2003 included $4 million and $5 million, respectively, of capital costs. Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 because of a plan amendment during the quarter, which required remeasurement of the plan's obligations. Based on the guidance in proposed FSP 106-b issued in March 2004, FirstEnergy has calculated a reduction of $318 million in the accumulated postretirement benefit obligation as a result of the federal subsidy provided under the Medicare Act. The subsidy reduced net periodic costs during the first quarter of 2004 by $10 million, which included increased amortization of the actuarial experience loss of $0.8 million, reduction of $6.1 million in past service cost, $1.1 million of current period service cost and $3.6 million of interest cost. Specific authoritative guidance on the accounting for the federal subsidy is pending, and when issued, could require a change to previously reported information. In addition, the plan amendment announced in the first quarter of 2004 reduced postretirement benefit costs during the quarter by $9.2 million as a result of increased cost-sharing by employees and retirees effective January 1, 2005. 5 - INTERNATIONAL DIVESTITURES: FirstEnergy completed the sale of its international assets during the quarter ended March 31, 2004 with the sales of its remaining 20.1 percent interest in Avon on January 16, 2004, and its 28.67 percent interest in TEBSA on January 30, 2004. Impairment charges related to Avon and TEBSA were recorded in the fourth quarter of 2003 and no gain or loss was recognized upon the sales in 2004. Avon, TEBSA and other international assets sold in 2003 were acquired as part of FirstEnergy's November 2001 merger with GPU. 6 - REGULATORY MATTERS: In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation contain 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 PLR obligations to customers in the Companies' service areas; o allowing recovery of transition costs (sometimes referred to as stranded investment); o itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and transition costs recovery charges; o deregulating the Companies' electric generation businesses; o continuing regulation of the Companies' transmission and distribution system; and o requiring corporate separation of regulated and unregulated business activities. 12 Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26 and 27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. 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 recovery period extension is related to the customer shopping incentives recovery discussed below. 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 SFAS 71 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. 13 Also as part of the settlement agreement, FirstEnergy gives 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. Subject to approval by the PUCO, recovery will be accomplished by extending the respective transition cost recovery period. On October 21, 2003, the Ohio EUOC filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing the Ohio EUOC's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service for the Ohio EUOC's customers. Beginning in 2006, customers would pay market prices for generation as determined by the auction. Under the Rate Stabilization Plan option, customers would have price and supply stability through 2008 - three years beyond the end of the market development period - as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually to ensure that customers pay the lowest available prices; extension of the Ohio EUOC's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, the Ohio EUOC are requesting: o Extension of the transition cost amortization period for OE from 2006 to 2007; for CEI from 2008 to mid-2009 and for TE from mid-2007 to mid-2008; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. Oral arguments were held before the PUCO on April 21 and a decision is expected from the PUCO in the Spring of 2004. Transition Cost Amortization OE, CEI and TE amortize transition costs (see Regulatory Matters - Ohio) using the effective interest method. Under the Ohio transition plan, total transition cost amortization is expected to approximate the following for 2004 through 2009. (In millions) --------------------------------------- 2004...................... $794 2005...................... 922 2006...................... 371 2007...................... 208 2008...................... 164 2009...................... 46 --------------------------------------- 14 The decrease in amortization beginning in 2006 results from the termination of generation-related transition cost recovery under the Ohio transition plan. 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 had been in effect at increasing levels through July 2003. The Final Order also confirmed the establishment of a non-bypassable SBC to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable 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 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 and there would be an adjustment to goodwill. In addition, the Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. Under NJBPU authorization in 2002, JCP&L issued through its wholly owned subsidiary, JCP&L Transition, $320 million of transition bonds (recognized on the Consolidated Balance Sheet) which securitized the recovery of these costs and which provided for a usage-based non-bypassable TBC and for the transfer of the bondable transition property to another entity. Prior to August 1, 2003, JCP&L's PLR obligation to provide BGS to non-shopping customers was 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 NUG agreements exceed amounts collected through BGS and MTC rates. As of March 31, 2004, the accumulated deferred cost balance totaled approximately $425 million, after the charge discussed below. 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's two August 2002 rate filings requested increases in base electric rates of approximately $98 million annually and requested the recovery of 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. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision, which reduced JCP&L's annual revenues by approximately $62 million effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base for six to twelve months. During that period, JCP&L will initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The net revenue decrease from the NJBPU's decision consists of a $223 million decrease in the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC. The MTC allows for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. As a result, JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and other regulatory assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on August 15, 2003 with respect to the following issues: (1) the disallowance of the $153 million deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7 million of disallowed costs to achieve merger savings. On October 10, 2003, the NJBPU held the motion in abeyance until the final NJBPU decision and order which is expected to be issued in the second quarter of 2004. JCP&L's BGS obligation for the twelve month period beginning August 1, 2003 was auctioned in February 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. The BGS auction for the subsequent period was completed in February 2004. The NJBPU adjusted the generation component of JCP&L's retail rates on August 1, 2003 to reflect the results of the BGS auction. On April 28, 2004, the NJBPU directed JCP&L to file testimony by the end of May 2004, either supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers, or, alternatively, proposing a reduction, termination or capping of the funding. JCP&L cannot predict the outcome of this matter. 15 Pennsylvania The PPUC authorized in 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 and would be an adjustment to goodwill. In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later denied in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision also affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287.1 million, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. As a result, FirstEnergy recorded in 2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to income for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million. On April 2, 2003, the PPUC remanded the issue relating to merger savings to the Office of Administrative Law for hearings, directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003, voiding the Settlement Stipulation in its entirety and reinstating Met-Ed's and Penelec's restructuring settlement previously approved by the PPUC. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day's notice. In response to that order, Met-Ed and Penelec filed these supplements to their tariffs to become effective October 24, 2003. On October 8, 2003, Met-Ed and Penelec filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC's findings would not impair their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed and Penelec for the NUG trust fund refund, denying Met-Ed's and Penelec's other clarification requests and granting ARIPPA's petition with respect to the accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 27, 2003, a Commonwealth Court judge issued an Order denying Met-Ed's and Penelec's objection without explanation. Due to the vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed and Penelec, in order to preserve their rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC's October 2 and October 16 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's objection was intended to be denied on the merits. In addition to these findings, Met-Ed and Penelec, in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC's findings in their Orders. Effective September 1, 2002, Met-Ed and Penelec agreed to purchase a portion of their PLR requirements from FES through a wholesale power sale agreement. The PLR sale 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 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 a fixed price 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 16 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 current market prices. In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. Met-Ed, Penelec and Penn are currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed's, Penelec's and Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Met-Ed's, Penelec's and Penn's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year end of 2004. FirstEnergy is unable to predict the outcome of the investigation or the impact of the PPUC order. 7 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS: EITF Issue No. 03-6, "Participating Securities and the Two-Class Method Under Financial Accounting Standards Board Statement No. 128, Earnings per Share" On March 31, 2004, the FASB ratified the consensus reached by the EITF on Issue 03-6. The issue addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of a company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-6 is effective for fiscal periods beginning after March 31, 2004. FirstEnergy is currently evaluating the effect of adopting EITF 03-6. FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on FirstEnergy's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of variable interest entities. For the quarter ended March 31, 2004, FirstEnergy evaluated, among other entities, its power purchase agreements and determined that it is possible that nine NUG entities might be considered variable interest entities. FirstEnergy has requested but not received the information necessary to determine whether these entities are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. Purchased power costs from these entities during the first quarters of 2004 and 2003 were $51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec - $7 million) and $56 million (JCP&L - $34 million, Met-Ed - $15 million and Penelec - $7 million), respectively. FirstEnergy is required to continue to make exhaustive 17 efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not "Held for Trading Purposes" as Defined in EITF Issue 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." In July 2003, the EITF reached a consensus that determining whether realized gains and losses on physically settled derivative contracts not "held for trading purposes" should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. The consideration of the facts and circumstances, including economic substance, should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. The adoption of this consensus effective January 1, 2004, did not have a material impact on the Companies' financial statements. 8 - SEGMENT INFORMATION: FirstEnergy operates under two reportable segments: regulated services and competitive services. The aggregate "Other" segments do not individually meet the criteria to be considered a reportable segment. "Other" consists of interest expense related to holding company debt; corporate support services and the international businesses acquired in the 2001 merger. FirstEnergy's primary segment is its regulated services segment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOC in Ohio, Pennsylvania and New Jersey (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec and ATSI). The competitive services business segment consists of the subsidiaries (FES, FSG, MYR, MARBEL and FirstCom) that operate unregulated energy and energy-related businesses, including the operation of generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business (see Note 6 - Regulatory Matters). The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition costs recovery. The competitive services segment has responsibility for FirstEnergy generation operations as discussed under Note 6. As a result, its revenues include all generation electric sales revenues (including the generation services to regulated franchise customers who have not chosen an alternative generation supplier) and all domestic unregulated energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation and sourcing of commodity requirements, providing local and long-distance phone service, as well as other competitive energy-application services. Segment reporting in 2003 was reclassified to conform with the current year business segment organizations and operations. Revenues from the competitive services segment now include all generation revenues including generation services to regulated franchise customers previously reported under the regulated services segment and now exclude revenues from power supply agreements with the regulated services segments previously reported as internal revenues. The regulated services segment results now exclude generation sales revenues and related generation commodity costs. Certain amounts (including transmission and congestion charges) were reclassified among purchased power, other operating costs and depreciation and amortization to conform with the current year presentation of generation commodity costs. In addition, segment results have been adjusted to reflect the reclassification of revenue, expense, interest expense and tax amounts of divested businesses reflected as discontinued operations (see Note 2). 18
Segment Financial Information ----------------------------- Regulated Competitive Reconciling Services Services Other Adjustments Consolidated --------- ----------- ----- ------------ ------------ (In millions) Three Months Ended: March 31, 2004 -------------- External revenues..................... $ 1,295 $ 1,873 $ 7 $ 8(a) $ 3,183 Internal revenues..................... -- -- 120 (120)(b) -- Total revenues..................... 1,295 1,873 127 (112) 3,183 Depreciation and amortization......... 393 9 10 -- 412 Net interest charges.................. 106 12 69 (15)(b) 172 Income taxes.......................... 147 -- (31) -- 116 Net income (loss)..................... 216 -- (42) -- 174 Total assets.......................... 29,336 2,285 964 -- 32,585 Total goodwill........................ 5,981 136 -- -- 6,117 Property additions.................... 90 45 3 -- 138 March 31, 2003 -------------- External revenues..................... $ 1,309 $ 1,874 $ 34 $ 4 (a) $ 3,221 Internal revenues..................... -- -- 124 (124) (b) -- Total revenues..................... 1,309 1,874 158 (120) 3,221 Depreciation and amortization......... 355 12 9 -- 376 Net interest charges.................. 124 12 104 (34) (b) 206 Income taxes.......................... 189 (66) (29) -- 94 Income before discontinued operations and cumulative effect of accounting change 257 (92) (51) -- 114 Net income (loss)..................... 358 (96) (44) -- 218 Total assets.......................... 30,417 2,449 1,421 -- 34,287 Total goodwill........................ 5,993 244 -- -- 6,237 Property additions.................... 118 79 27 -- 224
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. 19 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31, ------------------------------- 2004 2003 ---- ---- (In thousands, except per share amounts) REVENUES: Electric utilities........................................................ $ 2,177,033 $ 2,315,064 Unregulated businesses.................................................... 1,005,541 905,673 ----------- ----------- Total revenues........................................................ 3,182,574 3,220,737 ----------- ----------- EXPENSES: Fuel and purchased power.................................................. 1,134,326 1,100,636 Purchased gas............................................................. 153,528 224,797 Other operating expenses.................................................. 841,615 926,585 Provision for depreciation and amortization............................... 412,232 376,363 General taxes............................................................. 179,085 178,067 ----------- ----------- Total expenses........................................................ 2,720,786 2,806,448 ----------- ----------- INCOME BEFORE INTEREST AND INCOME TAXES...................................... 461,788 414,289 ----------- ----------- NET INTEREST CHARGES: Interest expense.......................................................... 172,864 200,261 Capitalized interest...................................................... (6,470) (9,152) Subsidiaries' preferred stock dividends................................... 5,281 14,542 ------------ ----------- Net interest charges.................................................. 171,675 205,651 ----------- ----------- INCOME TAXES................................................................. 116,114 94,258 ----------- ----------- INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................................... 173,999 114,380 Discontinued operations (net of income taxes of $3,211,000) (Note 2)......... -- 1,975 Cumulative effect of accounting change (net of income taxes of $72,516,000) (Note 2)..................................................... -- 102,147 ----------- ----------- NET INCOME................................................................... $ 173,999 $ 218,502 =========== =========== BASIC EARNINGS PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change.................................................... $0.53 $0.39 Discontinued operations (Note 2).......................................... -- -- Cumulative effect of accounting change (Note 2)........................... -- 0.35 ----- ----- Net income................................................................ $0.53 $0.74 ===== ===== WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING.......................... 327,057 293,886 ======= ======= DILUTED EARNINGS PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change.................................................... $0.53 $0.39 Discontinued operations (Note 2).......................................... -- -- Cumulative effect of accounting change (Note 2)........................... -- 0.35 ----- ----- Net income................................................................ $0.53 $0.74 ===== ===== WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING........................ 329,034 294,877 ======= ======= DIVIDENDS DECLARED PER SHARE OF COMMON STOCK................................. $0.375 $0.375 ====== ====== The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. 20
FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2004 2003 --------------------------- (In thousands) ASSETS CURRENT ASSETS: Cash and cash equivalents......................................................... $ 280,269 $ 113,975 Receivables- Customers (less accumulated provisions of $51,127,000 and $50,247,000 respectively, for uncollectible accounts)...................................... 937,026 1,000,259 Other (less accumulated provisions of $30,257,000 and $18,283,000 respectively, for uncollectible accounts)...................................... 295,728 505,241 Letter of credit collateralization................................................. 277,763 -- Materials and supplies, at average cost- Owned............................................................................ 337,473 325,303 Under consignment................................................................ 90,303 95,719 Prepayments and other.............................................................. 253,180 202,814 ----------- ----------- 2,471,742 2,243,311 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT: In service......................................................................... 21,917,840 21,594,746 Less--Accumulated provision for depreciation....................................... 9,242,621 9,105,303 ----------- ----------- 12,675,219 12,489,443 Construction work in progress...................................................... 583,927 779,479 ----------- ----------- 13,259,146 13,268,922 ----------- ----------- INVESTMENTS: Nuclear plant decommissioning trusts............................................... 1,419,743 1,351,650 Investments in lease obligation bonds ............................................. 968,039 989,425 Letter of credit collateralization ................................................ -- 277,763 Other.............................................................................. 919,430 878,853 ----------- ----------- 3,307,212 3,497,691 ----------- ----------- DEFERRED CHARGES: Regulatory assets.................................................................. 6,722,641 7,076,923 Goodwill........................................................................... 6,117,000 6,127,883 Other.............................................................................. 706,795 695,218 ----------- ----------- 13,546,436 13,900,024 ----------- ----------- $32,584,536 $32,909,948 =========== =========== LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt and preferred stock............................... $ 1,736,737 $ 1,754,197 Short-term borrowings ............................................................. 133,999 521,540 Accounts payable................................................................... 548,221 725,239 Accrued taxes...................................................................... 701,458 669,529 Lease market valuation liability................................................... 84,800 84,800 Other.............................................................................. 760,656 716,862 ----------- ----------- 3,965,871 4,472,167 ----------- ----------- CAPITALIZATION: Common stockholders' equity- Common stock, $.10 par value, authorized 375,000,000 shares- 329,836,276 shares outstanding................................................. 32,984 32,984 Other paid-in capital............................................................ 7,054,006 7,062,825 Accumulated other comprehensive loss............................................. (343,826) (352,649) Retained earnings................................................................ 1,655,919 1,604,385 Unallocated employee stock ownership plan common stock- 2,692,155 and 2,896,951 shares, respectively................................... (54,360) (58,204) ----------- ----------- Total common stockholders' equity............................................ 8,344,723 8,289,341 Preferred stock of consolidated subsidiaries not subject to mandatory redemption... 335,123 335,123 Long-term debt and other long-term obligations..................................... 10,150,067 9,789,066 ----------- ----------- 18,829,913 18,413,530 ----------- ----------- NONCURRENT LIABILITIES: Accumulated deferred income taxes.................................................. 2,137,839 2,178,075 Asset retirement obligations....................................................... 1,198,132 1,179,493 Power purchase contract loss liability............................................. 2,597,820 2,727,892 Retirement benefits................................................................ 1,615,837 1,591,006 Lease market valuation liability................................................... 999,850 1,021,000 Other.............................................................................. 1,239,274 1,326,785 ----------- ----------- 9,788,752 10,024,251 ----------- ----------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3).................................... ----------- ----------- $32,584,536 $32,909,948 =========== =========== The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these balance sheets. 21
FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, ------------------------ 2004 2003 ---- ---- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 173,999 $ 218,502 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization................................ 412,232 376,363 Nuclear fuel and lease amortization........................................ 21,874 14,918 Other amortization, net.................................................... (4,723) (4,613) Deferred costs recoverable as regulatory assets............................ (83,907) (94,311) Deferred income taxes, net................................................. 12,397 28,141 Investment tax credits, net................................................ (6,474) (6,259) Cumulative effect of accounting change (Note 2)............................ -- (174,663) Income from discontinued operations (Note 2)............................... -- (1,975) Receivables................................................................ 272,746 (1,898) Materials and supplies..................................................... (6,754) 11,413 Accounts payable........................................................... (177,018) (7,115) Accrued taxes.............................................................. 31,929 97,553 Accrued interest........................................................... 86,636 89,210 Deferred rents and sale/leaseback valuation liability...................... (16,297) (17,592) Prepayments and other current assets....................................... (47,031) (69,673) Other...................................................................... (19,986) 4,261 --------- --------- Net cash provided from operating activities.............................. 649,623 462,262 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt............................................................. 581,558 297,696 Redemptions and Repayments- Long-term debt............................................................. (268,920) (200,866) Short-term borrowings, net................................................. (387,541) (237,490) Net controlled disbursement activity......................................... (42,656) 14,444 Common stock dividend payments............................................... (122,465) (110,159) --------- --------- Net cash used for financing activities................................... (240,024) (236,375) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (138,406) (224,419) Nonutility generation trust withdrawals (contributions)...................... (50,614) 106,327 Contributions to nuclear decommissioning trusts.............................. (25,370) (25,263) Proceeds from asset sales.................................................... 11,439 60,572 Cash investments............................................................. 20,218 24,715 Other........................................................................ (60,572) (59,640) --------- --------- Net cash used for investing activities................................... (243,305) (117,708) --------- --------- Net increase in cash and cash equivalents....................................... 166,294 108,179 Cash and cash equivalents at beginning of period................................ 113,975 225,932 --------- --------- Cash and cash equivalents at end of period...................................... $ 280,269 $ 334,111 ========= ========= The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. 22
REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders 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, 2004, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2004 and 2003. 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, 2003, 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 asset retirement obligations as of January 1, 2003 as discussed in Note 2(F) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 9 to those consolidated financial statements) dated February 25, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, 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 7, 2004 23 FIRSTENERGY CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FirstEnergy's Business FirstEnergy Corp. is a registered public utility holding company headquartered in Akron, Ohio that provides regulated and competitive energy services (see Results of Operations - Business Segments). FirstEnergy continues to pursue its goal of being the leading supplier of energy and related services in portions of the midwest and mid-Atlantic regions of the United States, where it sees the best opportunities for growth. FirstEnergy's 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 continue providing 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 the 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 eight electric utility operating companies provide transmission and distribution services and comprise the nation's fifth largest investor-owned electric system, serving 4.4 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. Competitive services are principally provided by FES, FSG, MARBEL, MYR and FirstEnergy's majority owned FirstCom. Through its 50% interest in GLEP, MARBEL is involved in the exploration and production of oil and natural gas, and transmission and marketing of natural gas. Other subsidiaries provide a wide range of services, including heating, ventilation, air-conditioning, refrigeration, process piping, plumbing, electrical and facility control systems and high-efficiency electrotechnologies. Telecommunication services are also provided - local and long-distance phone service is provided to more than 65,000 customers. While competitive revenues have increased since 2001, regulated energy services continue to provide, in aggregate, the majority of FirstEnergy's revenues and earnings. Beginning in 2001, Ohio utilities that offered both competitive and regulated retail electric services were required to implement a corporate separation plan approved by the PUCO - one which provided a clear separation between regulated and competitive operations. FES provides competitive retail energy services while the EUOC provide regulated transmission and distribution services. FGCO, a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and operates those plants. Under the terms of the current corporate separation plan, the transfer of ownership of EUOC non-nuclear generating assets to FGCO would be substantially completed by the end of the Ohio market development period. All of the EUOC power supply requirements for the Ohio Companies (OE, CEI, and TE) and Penn are provided by FES to satisfy their PLR obligations, as well as their grandfathered wholesale contracts. FirstEnergy acquired international assets through the merger with GPU in November 2001. GPU Capital and its subsidiaries provided electric distribution services in foreign countries (see Results of Operations - Discontinued Operations). GPU Power and its subsidiaries owned and operated generation facilities in foreign countries. As of January 30, 2004, substantially all of the international operations were divested (see Note 5) - supporting FirstEnergy's commitment to focus on its core electric business. FirstEnergy's current focus includes: (1) enhancing customer service; (2) optimizing its generation portfolio; (3) minimizing unplanned extended generation outages; (4) effectively managing commodity supplies and risks; (5) reducing its cost structure; (6) enhancing its credit profile and financial flexibility; (7) managing the skills and diversity of its workforce; (8) continuing safe operations; and (9) satisfactory resolution of the pending Ohio rate plan. Reclassifications As further discussed in Note 8 to the Consolidated Financial Statements, amounts for purchased power, other operating costs and provisions for depreciation and amortization in FirstEnergy's 2003 Consolidated Statements of Income were reclassified to conform with the current year presentation of generation commodity costs. These reclassifications did not change previously reported 2003 results. In addition, as discussed in Note 2 to the Consolidated Financial Statements, reporting of discontinued operations also resulted in the reclassification of revenues, expenses and taxes. 24 Results of Operations Net Income and Earnings Per Share Net income in the first quarter of 2004 was $174 million or $0.53 per share of common stock (basic and diluted), compared to $218 million or $0.74 per share of common stock (basic and diluted) in the first quarter of 2003. Net income in the first quarter of 2003 included after-tax earnings from discontinued operations of $2 million and an after-tax credit of $102 million from the cumulative effect of an accounting change (basic and diluted earnings per share of $0.35) due to the adoption of SFAS 143. Excluding the cumulative effect of the accounting change in the first quarter of 2003, earnings increased to $0.53 per share of common stock (basic and diluted) from $0.39 per share of common stock (basic and diluted). Two major factors contributed to this improved performance -- reduced maintenance costs incurred as part of the extended outage at Davis-Besse (as the plant prepared for restart in 2004) and the absence of any nuclear refueling outage in the first three months of 2004 versus one refueling outage in the same period last year. In the third quarter of 2003, FirstEnergy completed the issuance and sale of 32.2 million shares of common stock (see Cash Flows from Financing Activities below) which were included in the calculation of earnings per share on a weighted average basis in the first quarter of 2004. The additional shares reduced earnings per share of common stock by $0.06 (basic and diluted). Three Months Ended March 31, ----------------------- FirstEnergy 2004 2003 ----------------------------------------------------------------------- (In millions) Total revenues............................. $3,183 $3,221 Income before interest and income taxes.... 462 414 Income before discontinued operations and cumulative effect of accounting change 174 114 Discontinued operations.................... -- 2 Cumulative effect of accounting change..... -- 102 ----------------------------------------------------------------------- Net Income................................. $ 174 $ 218 ----------------------------------------------------------------------- Basic Earnings Per Share: Income before discontinued operations and cumulative effect of accounting change $0.53 $0.39 Discontinued operations................. -- -- Cumulative effect of accounting change.. -- 0.35 ------------------------------------------------------------------------ Net Income................................. $0.53 $0.74 ======================================================================== Diluted Earnings Per Share: Income before discontinued operations and cumulative effect of accounting change $0.53 $0.39 Discontinued operations................. -- -- Cumulative effect of accounting change.. -- 0.35 ------------------------------------------------------------------------ Net Income................................. $0.53 $0.74 ======================================================================== Results of Operations - First Quarter of 2004 Compared With the First Quarter of 2003 Total revenues decreased $38 million in the first quarter of 2004, compared to the same period last year. The sources of changes in total revenues are summarized in the following table: 25 Three Months Ended March 31, ------------------ Increase Sources of Revenue Changes 2004 2003 (Decrease) --------------------------------------------------------------------- (In millions) Retail Electric Sales: EUOC - Wires and shopping deferrals $ 1,159 $ 1,213 $ (54) - Generation 758 785 (27) FES.............................. 171 121 50 Wholesale Electric Sales: EUOC............................. 124 221 (97) FES.............................. 444 284 160 ------------------------------------------------------------------ Electric Sales..................... 2,656 2,624 32 ------------------------------------------------------------------ Transmission Revenues.............. 76 9 67 Gas Sales.......................... 165 245 (80) Other Revenues: Regulated services................ 60 86 (26) Competitive services.............. 220 222 (2) International...................... -- 8 (8) Other.............................. 6 27 (21) ------------------------------------------------------------------- Total Revenues..................... $3,183 $3,221 $ (38) =================================================================== Changes in electric generation sales and distribution deliveries in the first quarter of 2004 from the same quarter of 2003 are summarized in the following table: Increase Changes in KWH Sales (Decrease) ----------------------------------------------------- Electric Generation Sales: Retail - EUOC.................................. (6.2)% FES................................... 24.4 % Wholesale............................... 19.5 % ----------------------------------------------------- Total Electric Generation Sales.......... 4.1 % ===================================================== EUOC Distribution Deliveries: Residential............................. (0.2)% Commercial.............................. -- % Industrial.............................. 0.8 % ----------------------------------------------------- Total Distribution Deliveries............ 0.2 % ===================================================== Retail sales by FirstEnergy's EUOC remain the largest source of revenues, contributing over 70% of electric revenues and over 60% of total revenues. The following major factors contributed to the $81 million reduction in retail electric revenues from FirstEnergy's regulated services segment in the first quarter of 2004 compared to the same period in 2003. Sources of the Changes in EUOC Retail Electric Revenue ------------------------------------------------------ Increase (Decrease) (In millions) ------------------------------------------------------ Changes in Demand: Alternative suppliers.................. $(56) Economic and other ................... 3 ------------------------------------------------------ (53) ------------------------------------------------------ Changes in Price: Rate changes........................... (32) Shopping credit........................ (7) Rate mix and other..................... 11 ------------------------------------------------------ (28) ------------------------------------------------------ Net Decrease............................. $ (81) ====================================================== Reductions in both demand and prices contributed to lower EUOC retail electric revenues. Customers shopping in FirstEnergy's franchise areas for alternative energy suppliers remained the largest single factor for the reduced demand. Alternative suppliers provided 24.1% of the total energy delivered to retail customers in the first quarter of 2004, compared to 18.9% in the same period of 2003. Distribution throughput increased slightly. Milder weather in the first quarter of 2004 compared to the unusually cold temperatures in the first quarter of 2003 contributed to reduced residential deliveries. However, economic and other factors contributed to increased industrial deliveries in the first quarter of 2004 compared to the same period last year. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision (see Regulatory Matters - New Jersey), which reduced JCP&L's distribution rates effective August 1, 2003. The lower rates reduced revenues by $32 million in the first quarter of 2004. EUOC sales to wholesale customers decreased by $97 26 million on a 44.1% reduction in kilowatt-hour sales - JCP&L's sales represented substantially all of the decrease. Electric sales by FES increased by $210 million primarily from additional spot sales to the wholesale market ($160 million). Higher electric sales to the wholesale market resulted from an 11% increase in internal generation available from FirstEnergy's nuclear (15%) and fossil (9%) generating plants. Retail sales increased by $50 million, primarily from customers within FirstEnergy's Ohio franchise areas switching to FES under Ohio's electricity choice program. FirstEnergy's regulated and unregulated subsidiaries record purchase and sales transactions with PJM on a gross basis in accordance with EITF 99-19. 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, 2004 and 2003 are summarized as follows: Three Months Ended March 31, ---------------------- 2004 2003 ------------------------------------------------------- (In millions) Sales......................... $366 $336 Purchases..................... 330 361 -------------------------------------------------------- FirstEnergy's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from PJM 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 (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. Natural gas sales were $80 million lower primarily due to the expiration of FES customer choice program contracts and reduced sales to large industrial and commercial customers. Sales to large commercial and industrial customers declined in the first quarter of 2004 from the same period in 2003 reflecting fewer customers and more moderate temperatures. The generation margin in the first quarter of 2004 improved by $53 million compared to the same period in 2003 as electric generation revenues increased faster than the related costs for fuel and purchased power. Higher electric generation sales resulted from additional sales to the wholesale market which benefited from increased internal generation. The improved generation margin occurred despite higher replacement power costs associated with the extended Davis-Besse outage (see Davis-Besse Restoration below). The gas margin decreased $9 million on falling sales.
Three Months Ended March 31, ---------------------- Increase Energy Revenue Net of Fuel and Purchased Power 2004 2003 (Decrease) ---------------------------------------------------------------------------------------------------- (In millions) Electric generation revenue........................... $1,497 $1,411 $86 Fuel and purchased power.............................. 1,134 1,101 33 -------------------------------------------------------------------------------------------------- Net................................................... 363 310 53 -------------------------------------------------------------------------------------------------- Gas revenue(1)........................................ 158 238 (80) Purchased gas......................................... 154 225 (71) -------------------------------------------------------------------------------------------------- Net................................................... 4 13 (9) -------------------------------------------------------------------------------------------------- Total Net............................................. $ 367 $ 323 $44 ================================================================================================== (1) Excludes 50% share of GLEP earnings.
Other factors contributing to the $48 million increase in income before interest and taxes include: o Lower nuclear production costs of $72 million primarily as a result of no nuclear refueling outages in the first quarter of 2004 compared to one refueling outage at Beaver Valley Unit 1 in last year's first quarter ($32 million) and reduced incremental maintenance costs at the Davis-Besse Plant ($35 million) related to its restart; o A net decrease of $19 million in other operating expenses as a result of reduced postretirement benefit plan expenses (see Postretirement Plans below) offset in part by additional severance costs and increased benefit costs for active employees; and 27 o Lower non-nuclear operating expenses primarily reflecting deferred planned outage work at FirstEnergy's fossil generating units ($10 million). Partially offsetting these lower costs were three factors: o Reduced revenues from distribution deliveries ($54 million); o Charges for depreciation and amortization that increased by $36 million primarily due to: higher charges resulting from increased amortization of the Ohio transition plan regulatory assets ($23 million), reduced shopping incentive deferrals under the Ohio transition plan ($4 million) and additional stranded cost amortization for Met-Ed and Penelec ($22 million). Partially offsetting these increases were reduced depreciation rates resulting from the JCP&L rate case ($11 million); and o Higher energy delivery costs of $10 million principally due to increased tree trimming activities and to a lesser extent JCP&L's accelerated reliability program. Income before discontinued operations and the cumulative effect of accounting changes increased $60 million from the comparable period last year. The change reflects reduced net interest charges of $34 million and increased income taxes of $22 million in addition to the changes discussed above. The decrease in interest expense is the result of debt and preferred stock redemptions and other financing activities. Proceeds from the issuance of 32.2 million shares of common stock in September 2003 accelerated the repayment of debt. Redemption and refinancing activities for debt and preferred stock aggregated approximately $653 million during the first quarter of 2004. The redemption and refinancing activities and pollution control note repricings are expected to result in annualized savings of $5 million. FirstEnergy also exchanged existing fixed-rate payments on outstanding debt (notional amount of $1.35 billion at March 31, 2004) 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 $11 million in the first quarter of 2004 as a result of these swaps. Discontinued Operations Net income in the first quarter of 2003 included after-tax earnings from discontinued operations of $2 million reflecting the reclassification of revenues and expenses associated with divestitures of its Argentina and Bolivia international businesses and the FSG subsidiaries, Colonial Mechanical, Webb Technologies and Ancoma, Inc., as well as NEO. Cumulative Effect of Accounting Change Results in the first quarter of 2003 included an after-tax credit to net income of $102 million recorded upon the adoption of SFAS 143 in January 2003. 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 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 $1.11 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 $1.24 billion. 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 and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $175 million increase to income, or $102 million net of income taxes. Postretirement Plans Resurgent equity markets in 2003, amendments to FirstEnergy's health care benefits plan in the first quarter of 2004 and the new Medicare Act signed by President Bush in December 2003 combined to reduce pensions and other postretirement costs -- despite continued increases in health care costs and projected trend rates. Combined, these employee benefit expenses decreased by $26 million in the first quarter of 2004 compared to the same period in 2003. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized) for the three months ended March 31, 2004 and 2003. 28 Three Months Ended Postretirement Benefits Expense(1) March 31, ----------------------------------------------------- 2004 2003 ---- ---- (In millions) Pension...................... $20 $31 OPEB......................... 26 41 ----------------------------------------------------- Total...................... $46 $72 ===================================================== (1).Excludes the capitalized portion of postretirement benefits costs (see Note 4 for total costs). The decrease in pension and OPEB expenses are included in various cost categories and have contributed to other cost reductions discussed above. See "Critical 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. In the first quarter of 2004, management made certain changes in presenting results for these two segments (see Note 8). The regulated services segment no longer includes a portion of generation services. The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition cost recovery. All generation services are now reported in the competitive services segment. As a result, its revenues include all generation electric sales revenues (including the generation services to regulated franchise customers who have not chosen an alternative generation supplier) and all domestic unregulated energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation, commodity sourcing and other competitive energy-application services such as heating, ventilating and air-conditioning. "Other" consists of interest expense related to holding company debt; corporate support services and the international businesses that were substantially divested by the first quarter of 2004. FirstEnergy's two major business segments include all or a portion of the following business entities: o The regulated services segment includes the regulated sale of electricity and distribution and transmission services by its eight electric utility operating companies in Ohio, Pennsylvania and New Jersey (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec and ATSI) o The competitive services business segment consists of the subsidiaries (FES, FSG, MYR, MARBEL and FirstCom) that operate unregulated energy and energy-related businesses, including the operation of generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business (see Note 6 - Regulatory Matters). Financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results to consolidated financial results is provided in Note 8 to the consolidated financial statements. Net income (loss) by business segment was as follows: Three Months Ended March 31, Net Income (Loss) --------------------- By Business Segment 2004 2003 ---------------------------------------------------- (In millions) Regulated services......... $ 216 $ 358 Competitive services....... -- (96) Other...................... (42) (44) ---------------------------------------------------- Total...................... $ 174 $ 218 ==================================================== Regulated Services - First Quarter 2004 versus First Quarter 2003 Financial results for the regulated services segment were as follows: Three Months Ended March 31, ------------------- Increase Regulated Services 2004 2003 (Decrease) -------------------------------------------------------------------------------- (In millions) Total revenues............................... $1,295 $1,309 $ (14) Income before interest and income taxes....... 468 570 (102) Income before cumulative effect of accounting changes.................................... 216 257 (41) Net Income.................................... 216 358 (142) -------------------------------------------------------------------------------- 29 The change in operating revenues resulted from the following sources: Three Months Ended March 31, --------------------- Increase Sources of Revenue Changes 2004 2003 (Decrease) ---------------------------------------------------------------------- (In millions) Electric sales............. $1,159 $1,213 $(54) Other sales................ 136 96 40 ---------------------------------------------------------------------- Total Sales................ $1,295 $1,309 $(14) ====================================================================== The decrease in electric revenues resulted from: o A net decrease of $54 million in retail sales -- a $58 million decrease in revenues from distribution deliveries partially offset by a $4 million decrease in shopping incentives to customers. o A net $40 million increase in other sales primarily due to higher transmission revenues. Lower revenues combined with increased expenses resulted in an $102 million decrease in income before interest and income taxes. Higher expenses included a $53 million increase in operating expenses from additional transmission expenses and energy delivery costs, as well as increased depreciation and amortization charges of $38 million. Competitive Services - First Quarter 2004 versus First Quarter 2003 Financial results for the competitive services segment were as follows: Three Months Ended March 31, ------------------ Increase Competitive Services 2004 2003 (Decrease) -------------------------------------------------------------------------------- (In millions) Total revenues................................... $1,873 $1,874 $ (1) Income (Loss) before interest and income tax benefit 13 (146) 159 Income (Loss) before discontinued operations and cumulative effect of accounting changes....... -- (92) 92 Net income (loss)................................ -- (96) 96 -------------------------------------------------------------------------------- The change in total revenues resulted from the following sources: Three Months Ended March 31, ------------------- Increase Sources of Revenue Changes 2004 2003 (Decrease) ---------------------------------------------------------------------- (In millions) Electric....................... $1,497 $1,411 $86 Natural Gas sales.............. 165 245 (80) Energy-related sales........... 178 187 (9) Other.......................... 33 31 2 ---------------------------------------------------------------------- Total Revenues................. $1,873 $1,874 $(1) ====================================================================== The increase in electric revenues resulted from: o Higher retail generation sales from sales through customer choice programs ($50 million) partially offset by lower generation sales from the EUOC ($27 million); and o Increased wholesale revenues of $160 million from FES (primarily into the spot market) offset in part by a $97 million decrease in EUOC sales to wholesale customers. Natural gas sales were $80 million lower primarily due to the expiration of customer choice programs in which FES participated and reduced sales to large industrial and commercial customers. Sales to large commercial and industrial customers declined reflecting fewer customers and more moderate temperatures than last year. The generation margin increased $53 million as electric generation revenues increased faster than the related costs for fuel and purchased power. Higher electric generation revenues resulted from additional sales to the wholesale market which benefited from increased internal generation. The improved generation margin occurred despite higher replacement power costs associated with the extended Davis-Besse outage (see Davis-Besse Restoration below). The margin on gas sales decreased $9 million on falling sales. Together with a higher net energy margin, reduced expenses contributed to a net $159 30 million increase in income before interest and income taxes. Major expense factors included the following: o Lower nuclear production costs of $72 million primarily as a result of no nuclear refueling outages in the first quarter of 2004 compared to one refueling outage at Beaver Valley Unit 1 in the first quarter last year ($32 million) and reduced incremental maintenance costs at the Davis-Besse Plant ($35 million) related to its restart. o A $10 million decrease in non-nuclear operating expenses primarily from deferred planned outage work at fossil generating units. o Reduced postretirement benefit plan expenses (see Postretirement Plans above) offset in part by increased benefit costs for active employees. Capital Resources and Liquidity FirstEnergy's cash requirements in 2004 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 two 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 $1.25 billion of revolving credit facilities. In the first quarter of 2004, FirstEnergy received $124 million of cash dividends from its subsidiaries and paid $122 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, 2004, FirstEnergy had $280 million of cash and cash equivalents, compared with $114 million as of December 31, 2003. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities FirstEnergy's consolidated net cash from operating activities is provided by its regulated and competitive energy services businesses (see Results of Operations - Business Segments above). Net cash provided from operating activities was $650 million in the first quarter of 2004 and $462 million in the first quarter of 2003, summarized as follows: Three Months Ended March 31, -------------------- Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 508 $ 363 Working capital and other............ 142 99 ------------------------------------------------------------- Total................................ $ 650 $ 462 ============================================================= (1)Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities increased $188 million due to a $145 million increase in cash earnings and a $43 million increase from changes in working capital. The working capital change resulted primarily from the net proceeds from the settlement of FirstEnergy's claim against NRG, Inc. for the terminated sale of four power plants. Cash Flows From Financing Activities The following table provides details regarding security issuances and redemptions during the first quarter of 2004 and 2003: 31 Three Months Ended March 31, -------------------- Securities Issued or Redeemed 2004 2003 ---------------------------------------------------------------------- (In millions) New Issues Pollution control notes................... $112 $ -- Senior notes.............................. 317 250 Unsecured notes........................... 153 -- Long-term revolver........................ -- 50 Other, primarily debt discount............ -- (2) ----------------------------------------------------------------------- $582 $298 Redemptions First mortgage bonds...................... $92 $40 Pollution control notes................... -- 50 Secured notes............................. 42 108 Long-term revolving credit................ 135 -- Other, primarily redemption premiums...... -- 3 ----------------------------------------------------------------------- $269 $201 Short-term Borrowings, Net .................... $(388) $(237) ------------------------------------------------------------------------ Net cash used for the above financing activities declined by $65 million in the first quarter of 2004 from the first quarter of 2003. The decrease in funds used for financing activities resulted from increased financing of $284 million that exceeded $219 million of additional redemptions and repayments during the first quarter of 2004 compared to the same period of 2003. FirstEnergy had approximately $134 million of short-term indebtedness as of March 31, 2004 compared to approximately $522 million as of December 31, 2003. Available borrowing capability as of March 31, 2004 included the following: FirstEnergy Borrowing Capability Holding Company OE Total ---------------------------------------------------------------------------- (In millions) Long-Term Revolver................ $ 875 $375 $1,250 Utilized.......................... (175) -- (175) Letters of Credit................. (183) -- (183) ---------------------------------------------------------------------------- Net............................... 517 375 892 ---------------------------------------------------------------------------- Short-Term Facilities: Revolver.......................... 375 125 500 Bank ............................. -- 34 34 ---------------------------------------------------------------------------- .................................. 375 159 534 ---------------------------------------------------------------------------- Utilized: Revolver.......................... -- -- -- Bank.............................. -- -- -- ---------------------------------------------------------------------------- Net............................... 375 159 534 ---------------------------------------------------------------------------- Amount Available.................. $ 892 $534 $1,426 ============================================================================ As of March 31, 2004, the Ohio companies and Penn had the aggregate capability to issue approximately $3.2 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds, although unsecured senior note indentures entered into by OE and CEI in 2004 limit each company's ability to issue secured debt, including FMBs, subject to certain exceptions. JCP&L, Met-Ed and Penelec no longer issue FMB other than (in the case of JCP&L and Penelec) 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, 2004, JCP&L and Penelec had the aggregate capability to issue $545 million of additional senior notes using FMB collateral. Because Met-Ed satisfied the provisions of its senior note indenture for the release of all FMBs held as collateral for senior notes in March 2004, it is no longer required to issue FMBs as collateral for future issuances of senior notes and therefore not limited as to the amount of senior notes it may issue. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $3.4 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2004. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock. In October 2003, FirstEnergy restructured its $1 billion 364-day revolving credit facility through a syndicated bank offering that was completed on October 23, 2003. The new syndicated FirstEnergy facilities consist of a $375 million 364-day revolving credit facility and a $375 million three-year revolving credit facility. Also on October 23, 2003, OE entered into a syndicated $125 million 364-day revolving credit facility and a syndicated $125 million three-year revolving credit facility. Combined with an existing syndicated $500 million three-year facility for FirstEnergy, maturing in November 2004, and an existing syndicated $250 million two-year facility for OE, 32 maturing in May 2005, FirstEnergy's primary syndicated credit facilities total $1.75 billion. These facilities are intended to provide liquidity to meet the short-term working capital requirements of FE and its subsidiaries. Available borrowing capacity under existing facilities totaled $1.426 billion as of March 31, 2004. Borrowings under these facilities are conditioned on FirstEnergy and/or OE maintaining compliance with certain financial covenants in the agreements. FirstEnergy, under its $375 million 364-day and $375 million three-year facilities, and OE, under its $125 million 364-day and $250 million two-year facilities, are each required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually-defined fixed charge coverage ratio of no less than 2 to 1. Under its $500 million three-year facility, FirstEnergy is required to maintain a debt to total capitalization ratio of no more than 0.69 to 1 and a contractually-defined fixed charge coverage ratio for the most recent fiscal quarter of no less than 1.5 to 1. FirstEnergy and OE are in compliance with all of these financial covenants. The ability to draw on each of these facilities is also conditioned upon FirstEnergy or OE making certain representations and warranties to the lending banks prior to drawing on their respective facilities, including a representation that there has been no material adverse change in its business, its condition (financial or otherwise), its results of operations, or its prospects. None of FirstEnergy's or OE's primary credit facilities contain provisions, whereby their ability to borrow would be restricted or denied, or repayment of outstanding loans under the facilities accelerated, as a result of any change in the credit ratings of FirstEnergy or OE by any of the nationally-recognized rating agencies. Borrowings under each of the primary facilities do contain "pricing grids", whereby the cost of funds borrowed under the facilities is related to the credit ratings of the company borrowing the funds. FirstEnergy's regulated companies have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among its competitive companies. FirstEnergy Service Company administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and competitive subsidiaries, as well as proceeds available from bank borrowings. For the regulated companies, available bank borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities. For the competitive companies, available bank borrowings include only the $1.25 billion of FirstEnergy's revolving credit facility. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. For the regulated and competitive money pools, the rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2004 was 1.30% for the regulated companies' pool and 1.57% for the competitive companies' pool. In January and March of 2004, FirstEnergy executed four fixed-to-floating interest rate swap agreements with notional amounts of $50 million each on underlying EUOC senior notes and subordinated debentures with an average fixed rate of 5.73%. In March 2004, Met-Ed, Penelec and Penn completed on-balance sheet, receivable financing transactions which allow each company to borrow up to $80 million, $75 million and $25 million, respectively. The borrowing rates are based on bank commercial paper rates. Met-Ed and Penelec are required to pay annual facility fees of 0.30% on the entire finance limit. Penn Power is required to pay an annual facility fee of 0.40% on the entire finance limit. The facilities were undrawn at the end of March 2004. These facilities mature on March 29, 2005. On March 25, 2004, Met-Ed issued $250 million principal amount of 4.875% Senior Notes due 2014. A portion of the proceeds were used to redeem $50 million aggregate principal amount of outstanding Met-Ed Medium Term Notes (MTNs) having a weighted average interest cost of 6.39%, and to pay down short-term debt. Met-Ed also intends to use a portion of the proceeds to redeem $100 million principal amount of Met-Ed Capital Trust's 7.35% Trust Preferred Securities in the second quarter of 2004 and to pay at maturity $40 million principal amount of Met-Ed's 6.34% MTNs maturing August 27, 2004. On March 31, 2004, Penelec issued $150 million principal amount of 5.125% Senior Notes due 2014. The proceeds of this transaction were used to redeem $125 million principal amount of 5.75% Senior Notes that matured on April 1, 2004 and to repay short-term debt. On April 23, 2004, JCP&L issued $300 million of 5.625% Senior Notes due 2016. The proceeds of this transaction will be used to redeem $40 million of 7.98% JCP&L Series C MTNs due 2023 and $50 million of 6.78% JCP&L Series C MTNs due 2005. The remaining proceeds will be used to fund the mandatory redemption of JCPL's $160 million of 7.125% FMB due October 1, 2004 and to reduce short-term debt. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the 33 service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy to restart the Davis-Besse nuclear plant was positive for credit quality because it would positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." Cash Flows From Investing Activities Net cash flows used for investing activities totaled $243 million in the first quarter of 2004, compared to net cash flows of $118 million used for investing activities for the same period of 2003. The $125 million change primarily resulted from a refunding payment of $51 million to a NUG trust fund in the first quarter 2004 compared to $106 million of withdrawals in the first quarter of 2003. The following table summarizes first quarter 2004 investments by FirstEnergy's regulated services and competitive services segments: Summary of First Quarter 2004 Property Cash Used for Investing Activities Additions Investments Other Total -------------------------------------------------------------------------------- Sources (Uses) (In millions) Regulated Services.................... $ (90) $(79)(1) $ (2) $(171) Competitive Services.................. (45) 20 2 (23) Other................................. (3) (26) (20) (49) -------------------------------------------------------------------------------- Total............................ $(138) $(85) $(20) $(243) ================================================================================ (1) Includes a $51 million refunding payment to a NUG trust fund. During the remaining three quarters of 2004, capital requirements for property additions and capital leases are expected to be approximately $666 million, including $86 million for nuclear fuel. FirstEnergy has additional requirements of approximately $902 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. FirstEnergy's current forecast reflects expenditures of approximately $2.3 billion for property additions and improvements from 2004-2006, of which approximately $720 million is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $315 million, of which approximately $86 million applies to 2004. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $281 million and $91 million, respectively, as the nuclear fuel is consumed. As of March 31, 2004, FirstEnergy had $278 million in deposits pledged as collateral to secure reimbursement obligations related to certain letters of credit supporting OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits had previously been classified as a noncurrent investment. OE expects to replace the cash collateralized LOC with a structure that would not require cash collateral. OE anticipates using the cash from the deposit to repay short term debt in the third quarter of 2004 and for other general corporate purposes. 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 letters of credit. As of March 31, 2004, the maximum potential future payments under outstanding guarantees and other assurances totaled $1.9 billion as summarized below: 34 Maximum Guarantees and Other Assurances Exposure ------------------------------------------------------------ (In millions) FirstEnergy Guarantees of Subsidiaries: Energy and Energy-Related Contracts(1)...... $ 862 Other (2)................................... 149 -------------------------------------------------------- 1,011 Surety Bonds.................................. 240 Letters of Credit (3)(4)...................... 677 -------------------------------------------------------- Total Guarantees and Other Assurances....... $ 1,928 ========================================================== (1) Issued for a one-year term, with a 10-day termination right by FirstEnergy. (2) Issued for various terms. (3) Includes letters of credit of $183 million issued for various terms under letter of credit capacity available in FirstEnergy's revolving credit agreement. (4) Includes unsecured letters of credit of approximately $216 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE, as well as collateralized letters of credit of $278 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE. 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 financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, 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 ongoing energy-related activities is remote. While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or "material adverse event" the immediate payment of cash collateral or provision of an LOC may be required. The following table summarizes collateral provisions as of March 31, 2004: Collateral Paid Total ----------------------- Remaining Collateral Provisions Exposure Cash Letters of Credit Exposure (1) -------------------------------------------------------------------------------- (In millions) Rating downgrade............ $228 $133 $18 $ 77 Adverse event............... 232 -- 69 163 -------------------------------------------------------------------------------- Total....................... $460 $133 $87 $240 ================================================================================ (1) As of April 12, 2004, FirstEnergy's remaining exposure was $237 million, with $141 million of cash and $72 million of letters of credit provided as collateral. 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. FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project in Colombia, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has provided the TEBSA project lenders a $60 million LOC, which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. This LOC granted FirstEnergy the ability to sell its remaining 20.1% interest in Avon. 35 OFF-BALANCE SHEET ARRANGEMENTS FirstEnergy has obligations that are not included on its Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are reflected as part of the operating lease payments. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.4 billion as of March 31, 2004. CEI and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $200 million of off-balance sheet financing as of March 31, 2004. As of March 31, 2004, off-balance sheet arrangements include certain statutory business trusts created by CEI, Met-Ed and Penelec to issue trust preferred securities aggregating $285 million. These trusts were included in the consolidated financial statements of FirstEnergy prior to the adoption of FIN 46R, but have subsequently been deconsolidated under FIN 46R (see Note 7 - New Accounting Standards and Interpretations). This deconsolidation has not resulted in any change in outstanding debt. FirstEnergy has equity ownership interests in certain various businesses that are accounted for using the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under contractual obligations above. 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 fluctuating electricity, natural gas, coal, nuclear fuel and emission allowance 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 2004 is summarized in the following table: 36
Increase (Decrease) in the Fair Value of Commodity Derivative Contracts Non-Hedge Hedge Total -------------------------------------------------------------------------------------------------- (In millions) Change in the Fair Value of Commodity Derivative Contracts: Outstanding net asset as of January 1, 2004................... $67 $ 12 $ 79 New contract value when entered............................... -- -- -- Additions/change in value of existing contracts............... (4) 6 2 Change in techniques/assumptions.............................. -- -- -- Settled contracts............................................. 1 (6) (5) ------------------------------------------------------------------------------------------------- Outstanding net asset as of March 31, 2004 (1)................ 64 12 76 ------------------------------------------------------------------------------------------------- Non-commodity Net Assets as of March 31, 2004: Interest Rate Swaps (2)....................................... -- 38 38 ------------------------------------------------------------------------------------------------- Net Assets - Derivatives Contracts as of March 31, 2004 (3)... $64 $ 50 $114 ================================================================================================= Impact of Changes in Commodity Derivative Contracts: (4) Income Statement Effects (Pre-Tax)............................ $(1) $ -- $ (1) Balance Sheet Effects: Other Comprehensive Income (Pre-Tax).......................... $-- $ -- $ -- Regulatory Liability.......................................... $(2) $ -- $ (2)
(1) Includes $59 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 $24 million of derivative contract fair value decrease, as of March 31, 2004, 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. Derivatives are included on the Consolidated Balance Sheet as of March 31, 2004 as follows: Balance Sheet Classification Non-Hedge Hedge Total ----------------------------------------------------------------------- (In millions) Current- Other Assets...................... $ 10 $11 $ 21 Other Liabilities................. (6) -- (6) Non-current- Other Deferred Charges............ 60 44 104 Other Noncurrent Liabilities...... -- (5) (5) ---------------------------------------------------------------------- Net assets........................ $ 64 $50 $ 114 ====================================================================== 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:
Source of Information - Fair Value by Contract Year 2004(1) 2005 2006 2007 Thereafter Total ----------------------------------------------------------------------------------------------------- (In millions) Prices actively quoted(2)............. $ 9 $ 2 $-- $-- $-- $11 Other external sources(3)............. 12 10 -- -- -- 22 Prices based on models................ -- -- 10 10 23 43 ----------------------------------------------------------------------------------------------------- Total(4)........................... $21 $12 $10 $10 $23 $76 =====================================================================================================
(1) For the last three quarters of 2004. (2) Exchange traded. (3) Broker quote sheets. (4) Includes $59 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. 37 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, 2004. Based on derivative contracts held as of March 31, 2004, an adverse 10% change in commodity prices would decrease net income by approximately $1 million for the next twelve months. Interest Rate Swap Agreements During the first quarter of 2004, FirstEnergy entered into fixed-to-floating interest rate swap agreements, as part of its ongoing effort to manage the interest rate risk of its debt portfolio. These derivatives are treated as fair value hedges of a 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, fixed interest rates and interest payment dates match those of the underlying obligations. As a result of the differences between fixed and variable debt rates, interest expense was $11 million lower in the first quarter of 2004. As of March 31, 2004, the debt underlying the interest rate swaps had a weighted average fixed interest rate of 5.44%, which the swaps have effectively converted to a current weighted average variable interest rate of 2.11%. Interest Rate Swaps
March 31, 2004 December 31, 2003 ---------------------------- ----------------------------- Notional Maturity Fair Notional Maturity Fair Denomination Amount Date Value Amount Date Value -------------------------------------------------------------------------------------------- (Dollars in millions) Fixed to Floating Rate (Fair value hedges) $200 2006 $ 5 $200 2006 $ 1 100 2008 2 50 2008 -- 100 2010 1 100 2010 1 100 2011 6 100 2011 1 450 2013 14 350 2013 (1) 150 2015 (3) 150 2015 (10) 150 2018 9 150 2018 1 50 2019 4 50 2019 1 50 2031 __-- ------------------------------------------------------------------------------------------- $1,350 $38 $1,150 $ (6) -------------------------------------------------------------------------------------------- Floating to Fixed Rate (1) (Cash flow hedges) $ 7 2005 $ -- -------------------------------------------------------------------------------------------
(1) FirstEnergy no longer had the cash flow hedges as of January 30, 2004 as a result of the divestiture of Los Amigos Leasing Company, Ltd.. - a subsidiary of GPU Power. Equity Price Risk Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $821 million and $779 million as of March 31, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $82 million reduction in fair value as of March 31, 2004. CREDIT RISK Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry. FirstEnergy maintains stringent credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts evidenced by a current weighted average risk S&P rating for energy contract counterparties of "BBB." As of March 31, 2004 the largest credit concentration to any counterparty was 8% - which is a currently rated investment grade counterparty. Outlook 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. 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 nonnuclear generating assets to FGCO 38 will be substantially completed by the end of the Ohio market development period. 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. 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 customers in the EUOC's service areas; o allowing recovery of transition costs (sometimes referred to as stranded investment) not otherwise recoverable in a competitive generation market; o itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and transition costs recovery charges; o deregulating the electric generation businesses; o continuing regulation of the EUOC's transmission and distribution systems; and o requiring corporate separation of regulated and unregulated business activities. Regulatory assets are costs which the respective regulatory agencies have authorized for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of the regulatory assets are expected to continue to be recovered under the provisions of the respective transition and regulatory plans as discussed below. The regulatory assets of the individual companies are as follows: March 31, December 31, Regulatory Assets 2004 2003 (Decrease) ---------------------------------------------------------------------------- (In millions) OE............................ $1,348 $1,451 $ (103) CEI........................... 1,022 1,056 (34) TE............................ 432 459 (27) Penn.......................... 15 28 (13) JCP&L......................... 2,457 2,558 (101) Met-Ed........................ 990 1,028 (38) Penelec....................... 459 497 (38) --------------------------------------------------------------------------- Total......................... $6,723 $7,077 $(354) =========================================================================== Regulatory assets by source are as follows: March 31, December 31, Increase Regulatory Assets By Source 2004 2003 (Decrease) ----------------------------------------------------------------------------- (In millions) Regulatory transition charge............. $6,088 $6,427 $(339) Customer shopping incentives............. 413 371 42 Customer receivables for future income taxes 315 340 (25) Societal benefits charge................. 81 81 -- Loss on reacquired debt.................. 74 75 (1) Postretirement benefits.................. 74 77 (3) Nuclear decommissioning, decontamination and spent fuel disposal costs.......... (106) (96) (10) Component removal costs.................. (327) (321) (6) Property losses and unrecovered plant costs 65 70 (5) Other.................................... 46 53 (7) --------------------------------------------------------------------------- Total.................................... $6,723 $7,077 $(354) =========================================================================== 39 Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Ohio FirstEnergy's transition plan for the Ohio EUOC included approval for recovery of transition costs, including regulatory assets, 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; granting 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 EUOC's retail customers; and freezing customer prices 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 EUOC 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. The Ohio EUOC 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. Subject to approval by the PUCO, recovery will be accomplished by extending the respective transition cost recovery period. On October 21, 2003, the Ohio EUOC filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or 40 o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing the Ohio EUOC's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service for the Ohio EUOC's customers. Beginning in 2006, customers would pay market prices for generation as determined by the auction. Under the Rate Stabilization Plan option, customers would have price and supply stability through 2008 - three years beyond the end of the market development period - as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually to ensure that customers pay the lowest available prices; extension of the Ohio EUOC's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, the Ohio EUOC are requesting: o Extension of the transition cost amortization period for OE from 2006 to 2007; for CEI from 2008 to mid-2009 and for TE from mid-2007 to mid-2008; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. Oral arguments were held before the PUCO on April 21 and a decision is expected from the PUCO in the Spring of 2004. 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's two August 2002 rate filings requested increases in base electric rates of approximately $98 million annually and requested the recovery of deferred energy 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. In July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision which reduced JCP&L's annual revenues by approximately $62 million effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base for the next six to twelve months. During that period, JCP&L will initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The revenue decrease in the decision consists of a $223 million decrease in the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC charge. The MTC allowed for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. As a result, JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million deferred energy costs and other regulatory assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on August 15, 2003 with respect to the following issues: (1) the disallowance of the $153 million deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7 million of disallowed costs to achieve merger savings. On October 10, 2003, the NJBPU held the motion in abeyance until the final NJBPU decision and order is issued. This is expected to occur in the second quarter of 2004. On July 5, 2003, JCP&L experienced a series of 34.5 kilo-volt sub-transmission line faults that resulted in outages on the New Jersey shore. The NJBPU instituted an investigation into these outages, and directed that a Special Reliability Master be hired to oversee the investigation. On December 8, 2003, the Special Reliability Master issued his Interim Report recommending that JCP&L implement a series of actions to improve reliability in the area affected by the outages. The NJBPU adopted the findings and recommendations of the Interim Report on December 17, 2003, and ordered JCP&L to implement the recommended actions on a staggered basis, with initial actions to be completed by March 31, 2004. JCP&L expects to spend $12.5 million implementing these actions during 2004. In late 2003, in accordance with a Settlement Stipulation concerning an August 2002 storm outage, the NJBPU engaged Booth & Associates to conduct an audit of the planning, operations and maintenance practices, policies 41 and procedures of JCP&L. The audit was expanded to include the July 2003 outage and was completed in January 2004. JCP&L is awaiting the issuance of the final audit report and is unable to predict the outcome of the audit; no liability has been accrued as of March 31, 2004. On April 28, 2004, the NJBPU directed JCP&L to file testimony by the end of May 2004, either supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers, or, alternatively, proposing a reduction, termination or capping of the funding. JCP&L cannot predict the outcome of this matter. Pennsylvania In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287.1 million, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. FirstEnergy recorded in 2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to income for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million. On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Met-Ed's and Penelec's restructuring settlement previously approved by the PPUC. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day's notice. In response to that order, Met-Ed and Penelec filed these supplements to their tariffs to become effective October 24, 2003. On October 8, 2003, Met-Ed and Penelec filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC's findings would not impair their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed and Penelec for the NUG trust fund refund and, denying Met-Ed's and Penelec's other clarification requests and granting ARIPPA's petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 27, 2003, one Commonwealth Court judge issued an Order denying Met-Ed's and Penelec's objection without explanation. Due to the vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed and Penelec, in order to preserve their rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC's October 16 and October 22 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's objection was intended to be denied on the merits. In addition to these findings, Met-Ed and Penelec, in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC's findings in their Orders. Effective September 1, 2002, Met-Ed and Penelec agreed to purchase a portion of their PLR requirements from FES through a wholesale power sale agreement. The PLR sale 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 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 a fixed price 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 current market prices. 42 In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. FirstEnergy is currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed's, Penelec's and Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Met-Ed's, Penelec's and Penn's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year end of 2004. FirstEnergy is unable to predict the outcome of the investigation or the impact of the PPUC order. Davis-Besse Restoration On April 30, 2002, the NRC initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process was 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. This process led to the NRC's March 8, 2004 approval of Davis-Besse's restart. Restart activities included both hardware and management issues. In addition to refurbishment and installation work at the plant, FENOC made significant management and human performance changes with the intent of enhancing the proper safety culture throughout the workforce. The focus of activities in the first quarter of 2004 involved management and human performance issues. As a result, incremental maintenance costs declined in the first quarter of 2004 compared to the same period in 2003 as emphasis shifted to performance issues; however, replacement power costs were higher in the first quarter of 2004. The plant's generating equipment was tested in March in preparation for resumption of operation. On April 4, 2004, Davis-Besse resumed generating electricity at 100% power. Incremental costs associated with the extended Davis-Besse outage for the first quarter of 2004 and 2003 were as follows: Three Months Ended March 31, ------------------- Increase Costs of Davis-Besse Extended Outage 2004 2003 (Decrease) ----------------------------------------------------------------------------- (In millions) Incremental Expense Replacement power................. $64 $52 $ 12 Maintenance....................... 1 36 (35) -------------------------------------------------------------------------- Total......................... $65 $88 $(23) ========================================================================== Incremental Net of Tax Expense...... $38 $52 $(14) ========================================================================== Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. 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 that 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. Overall, FirstEnergy believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NOx and SO2 emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO2 emissions would be reduced by approximately 3.6 million tons in 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities. 43 On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as "maximum achievable control technologies" (MACT) based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year. The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. 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. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of March 31, 2004. In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the U.S. Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18% through 2012. The Companies cannot currently estimate the financial impact of climate change policies although the potential restrictions on CO2 emissions could require significant capital and other expenditures. However, the CO2 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which includes low or non-CO2 emitting gas-fired and nuclear generators. Power Outages In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory. Since July 1999, this litigation has involved a substantial amount of legal discovery including interrogatories, request for production of documents, preservation and inspection of evidence, and depositions of the named plaintiffs and many JCP&L employees. In addition, there have been many motions filed and argued by the parties involving issues such as the primary jurisdiction and findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class decertification, and the damages claimed by the plaintiffs. In January 2000, the NJ Appellate Division determined that the trial court has proper jurisdiction over this litigation. In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict products liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings have been appealed to the Appellation Division and oral argument is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of March 31, 2004. 44 On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. -Canada Power System Outage Task Force released its final report on this outage. The final report supercedes the interim report that had been issued in November, 2003. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including, an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has undertaken several initiatives, some prior to and some since the August 14th power outage, to enhance reliability which are consistent with these and other recommendations and believes it will complete those relating to summer 2004 by June 30 (see Regulatory Matters above). As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Davis-Besse FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse plant. FirstEnergy is unable to predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002. Further, a petition was filed with the NRC on March 29, 2004 by a group objecting to the NRC's restart order of the Davis-Besse Nuclear Power Station. The Petition seeks, among other things, suspension of the Davis-Besse operating license. If it were ultimately determined that FirstEnergy has legal liability or is otherwise made subject to enforcement action based on any of the above matters with respect to the Davis-Besse outage, it could have a material adverse effect on FirstEnergy's financial condition and results of operations. Other Legal Matters Various lawsuits, claims and proceedings related to FirstEnergy's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant not otherwise discussed above are described below. Legal proceedings have been filed against FirstEnergy in connection with, among other things, the restatements in August 2003, by FirstEnergy and its Ohio utility subsidiaries of previously reported results, the August 14th power outage described above, and the extended outage at the Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the issues raised include alleged violations of federal securities laws, breaches of fiduciary duties under state law by FirstEnergy directors and officers, and damages as a result of one or more of the noted events. The securities cases have been consolidated into one action pending in federal court in Akron. The derivative actions filed in federal court likewise have been consolidated as a separate matter, also in federal court in Akron. There also are pending derivative actions in state court. FirstEnergy's Ohio utility subsidiaries were also named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14th power outage. FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be instituted against them. In particular, if FirstEnergy were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on its financial condition and results of operations. Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. 45 CRITICAL ACCOUNTING POLICIES FirstEnergy prepares its consolidated financial statements in accordance with GAAP. 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. 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 - $6.7 billion as of March 31, 2004. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. FirstEnergy continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, FirstEnergy enters into a significant number of commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments. Revenue Recognition FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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. 46 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 recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 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. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% 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. Ohio Transition Cost Amortization In connection with FirstEnergy's transition plan, the PUCO determined allowable transition costs based on amounts recorded on the regulatory books of the Ohio electric utilities. These costs exceeded those deferred or capitalized on FirstEnergy's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). FirstEnergy uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company. In computing the transition cost amortization, FirstEnergy includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, FirstEnergy periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might 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 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). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, FirstEnergy recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements") to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. 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 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), the goodwill is tested for impairment. If an impairment is indicated FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a reporting 47 unit's goodwill and the carrying value of the goodwill. FirstEnergy's annual review was completed in the third quarter of 2003. As a result of that review, a non-cash goodwill impairment charge of $122 million was recognized in the third quarter of 2003, reducing the carrying value of FSG. 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, 2004, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS EITF Issue No. 03-6, "Participating Securities and the Two-Class Method Under Financial Accounting Standards Board Statement No. 128, Earnings per Share" On March 31, 2004, the FASB ratified the consensus reached by the EITF on Issue 03-6. The issue addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of a company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06 is effective for fiscal periods beginning after March 31, 2004. FirstEnergy is currently evaluating the effect of adopting EITF 03-6. FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on FirstEnergy's financial statements for the quarter ended March 31, 2004. For the quarter ended March 31, 2004, FirstEnergy evaluated, among other entities, its power purchase agreements and determined that it is possible that nine NUG entities might be considered variable interest entities. FirstEnergy has requested but not received the information necessary to determine whether these entities are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. Purchased power costs from these entities during the first quarters of 2004 and 2003 were $51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec - $7 million) and $56 million (JCP&L - $34 million, Met-Ed - $15 million and Penelec - $7 million), respectively. FirstEnergy is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not "Held for Trading Purposes" as Defined in EITF Issue 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." In July 2003, the EITF reached a consensus that determining whether realized gains and losses on physically settled derivative contracts not "held for trading purposes" should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. The consideration of the facts and circumstances, including economic substance, should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. The adoption of this consensus effective January 1, 2004, did not have a material impact on the Companies' financial statements. 48 OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31, ------------------------- 2004 2003 -------- -------- (In thousands) OPERATING REVENUES.............................................................. $743,295 $742,743 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 15,070 12,850 Purchased power.............................................................. 249,881 243,828 Nuclear operating costs...................................................... 79,641 125,368 Other operating costs........................................................ 81,474 90,273 -------- -------- Total operation and maintenance expenses................................... 426,066 472,319 Provision for depreciation and amortization.................................. 124,729 108,385 General taxes................................................................ 48,566 48,256 Income taxes................................................................. 61,574 43,701 -------- -------- Total operating expenses and taxes......................................... 660,935 672,661 -------- -------- OPERATING INCOME................................................................ 82,360 70,082 OTHER INCOME.................................................................... 12,471 13,501 -------- -------- INCOME BEFORE NET INTEREST CHARGES.............................................. 94,831 83,583 -------- -------- NET INTEREST CHARGES: Interest on long-term debt................................................... 16,589 24,488 Allowance for borrowed funds used during construction and capitalized interest (1,381) (1,380) Other interest expense....................................................... 2,890 2,478 Subsidiaries' preferred stock dividend requirements.......................... 640 912 -------- -------- Net interest charges....................................................... 18,738 26,498 -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 76,093 57,085 Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 2) -- 31,720 ------- -------- NET INCOME...................................................................... 76,093 88,805 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 561 659 -------- -------- EARNINGS ON COMMON STOCK........................................................ $ 75,532 $ 88,146 ======== ======== The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements. 49
OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2004 2003 ---------- ----------- (In thousands) ASSETS UTILITY PLANT: In service...................................................................... $5,304,122 $5,269,042 Less-Accumulated provision for depreciation..................................... 2,611,122 2,578,899 ---------- ---------- 2,693,000 2,690,143 ---------- ---------- Construction work in progress- Electric plant................................................................ 143,478 145,380 Nuclear Fuel.................................................................. 554 554 ---------- ---------- 144,032 145,934 ---------- ---------- 2,837,032 2,836,077 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Investment in lease obligation bonds............................................ 383,088 383,510 Letter of credit collateralization.............................................. -- 277,763 Nuclear plant decommissioning trusts............................................ 394,705 376,367 Long-term notes receivable from associated companies ........................... 209,271 508,594 Other........................................................................... 56,131 59,102 ---------- ---------- 1,043,195 1,605,336 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents....................................................... 1,323 1,883 Receivables- Customers (less accumulated provisions of $8,714,000 and $8,747,000, respectively, for uncollectible accounts)................................... 267,315 280,538 Associated companies.......................................................... 500,570 436,991 Other (less accumulated provisions of $1,724,000 and $2,282,000 for uncollectible accounts)................................................. 29,887 28,308 Letter of credit collateralization.............................................. 277,763 -- Notes receivable from associated companies...................................... 616,912 366,501 Materials and supplies, at average cost......................................... 82,575 79,813 Prepayments and other........................................................... 26,219 14,390 ---------- ---------- 1,802,564 1,208,424 ---------- ---------- DEFERRED CHARGES: Regulatory assets............................................................... 1,363,242 1,477,969 Property taxes.................................................................. 59,279 59,279 Unamortized sale and leaseback costs............................................ 64,284 65,631 Other........................................................................... 64,353 64,214 ---------- ---------- 1,551,158 1,667,093 ---------- ---------- $7,233,949 $7,316,930 ========== ========== 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.......................................... (35,657) (38,693) Retained earnings............................................................. 544,466 522,934 ---------- ---------- Total common stockholder's equity........................................... 2,607,538 2,582,970 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 Long-term debt and other long-term obligations.................................. 1,160,452 1,179,789 ---------- ---------- 3,868,060 3,862,829 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock............................ 428,438 466,589 Short-term borrowings- Associated companies.......................................................... 67,849 11,334 Other......................................................................... 131,367 171,540 Accounts payable- Associated companies.......................................................... 512,386 271,262 Other......................................................................... 7,834 7,979 Accrued taxes................................................................... 248,768 560,345 Accrued interest................................................................ 24,157 18,714 Other........................................................................... 99,116 58,680 ---------- ---------- 1,519,915 1,566,443 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes............................................... 824,832 867,691 Accumulated deferred investment tax credits..................................... 72,664 75,820 Asset retirement obligation..................................................... 322,929 317,702 Retirement benefits............................................................. 342,952 331,829 Other........................................................................... 282,597 294,616 ---------- ---------- 1,845,974 1,887,658 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................. ---------- ---------- $7,233,949 $7,316,930 ========== ========== The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets. 50
OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, ---------------------------- 2004 2003 --------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 76,093 $ 88,805 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization................................ 124,729 108,385 Nuclear fuel and lease amortization........................................ 11,261 7,106 Deferred income taxes, net................................................. (26,387) 7,683 Investment tax credits, net................................................ (3,658) (3,704) Cumulative effect of accounting change (Note 2)............................ -- (54,109) Receivables................................................................ (51,935) (29,909) Materials and supplies..................................................... (2,762) (1,298) Accounts payable........................................................... 240,979 14,470 Accrued taxes.............................................................. (311,577) 6,051 Accrued interest........................................................... 5,443 2,437 Deferred lease costs....................................................... 33,030 31,683 Prepayments and other current assets ...................................... (11,829) (14,893) Accrued retirement benefit obligations..................................... 11,123 2,679 Accrued compensation, net.................................................. 4,404 (5,802) Other...................................................................... 16,562 (6,067) --------- --------- Net cash provided from operating activities.............................. 115,476 153,517 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt............................................................. 30,000 -- Short-term borrowings, net................................................. 16,341 -- Redemptions and Repayments- Long-term debt............................................................. (97,001) (19,493) Short-term borrowings, net................................................. -- (232,278) Dividend Payments- Common stock............................................................... (54,000) (13,000) Preferred stock............................................................ (561) (659) --------- --------- Net cash used for financing activities................................... (105,221) (265,430) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (37,661) (68,367) Contributions to nuclear decommissioning trusts.............................. (7,885) (7,885) Nuclear decommissioning trust investments.................................... (10,453) 4,777 Associated company loan activities, net...................................... 48,912 173,250 Other........................................................................ (3,728) 3,946 --------- --------- Net cash provided from (used for) investing activities................... (10,815) 105,721 --------- --------- Net decrease in cash and cash equivalents....................................... (560) (6,192) Cash and cash equivalents at beginning of period................................ 1,883 20,512 --------- --------- Cash and cash equivalents at end of period...................................... $ 1,323 $ 14,320 ========= ========= The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements. 51
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, 2004, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2004 and 2003. 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, 2003, 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 (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(F) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated February 25, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, 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 7, 2004 52 OHIO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION OE is a wholly owned, electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. OE and Penn (OE Companies) also provide generation services to those customers electing to retain them as their power supplier. The OE Companies provide power directly to wholesale customers under previously negotiated contracts, as well as to alternative energy suppliers under OE's transition plan. The OE Companies have unbundled the price of electricity into its component elements -- including generation, transmission, distribution and transition charges. Power supply requirements of the OE Companies are provided by FES -- an affiliated company. Results of Operations --------------------- Earnings on common stock in the first quarter of 2004 decreased to $76 million from $88 million in the first quarter of 2003. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $32 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $76 million in the first three months of 2004, compared to $57 million for the same period of 2003. Improved results in the first quarter of 2004 reflect lower operating expenses - primarily nuclear operating costs, and reduced financing costs compared with the first quarter of 2003. Partially offsetting these improvements were higher nuclear fuel and purchased power costs and increased amortization of regulatory assets. Operating revenues increased by $0.6 million or 0.1% in the first quarter of 2004 compared with the same period in 2003. The higher revenues primarily resulted from additional sales to FES which were substantially offset by lower generation retail sales to residential and commercial customers and reduced revenue from distribution throughput. Total retail electric revenues decreased by $7 million in the first quarter of 2004 compared to the first quarter of 2003 reflecting reduced consumption due principally to milder weather and a continued sluggish economy in our service area ($13 million) partially offset by higher composite prices from a change in customer sales by class ($6 million). Kilowatt-hour sales to retail customers declined by 3.3% in the first quarter of 2004 compared to the same quarter of 2003, which reduced generation sales revenue by $2 million. The decline reflected the increase of 2.3 percentage points in electric generation services provided by alternative suppliers as a percent of total sales delivered in OE's franchise area in 2004 from the first quarter of 2003. In addition, distribution deliveries decreased by 1.6% in the first quarter of 2004 compared with the first quarter of 2003, with declines in all customer sectors (residential, commercial and industrial). Sales revenues from wholesale customers increased by $10 million in the first quarter of 2004 compared to the same period of 2003, due to a 23% increase in nuclear generation available for sale to FES partially offset by lower composite prices. The increased generation was due to the absence in 2004 of the Beaver Valley Unit 1 refueling outage in 2003. Changes in electric generation sales and distribution deliveries in the first quarter of 2004 from the same quarter of 2003 are summarized in the following table: Changes in Kilowatt-Hour Sale --------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. (3.3)% Wholesale............................... 9.1% --------------------------------------------------- Total Electric Generation Sales........... 2.2% =================================================== Distribution Deliveries: Residential............................. (2.1)% Commercial.............................. (0.6)% Industrial.............................. (1.8)% ---------------------------------------------------- Total Distribution Deliveries............. (1.6)% ==================================================== 53 Operating Expenses and Taxes Total operating expenses and taxes decreased by $12 million in the first quarter of 2004 from the first quarter of 2003. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes ----------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................. $ 2 Purchased power ................................. 6 Nuclear operating costs.......................... (45) Other operating costs............................ (9) ------------------------------------------------------------- Total operation and maintenance expenses....... (46) Provision for depreciation and amortization...... 16 General taxes.................................... -- Income taxes..................................... 18 ------------------------------------------------------------ Total operating expenses and taxes............. $(12) ============================================================= Higher fuel costs in the first quarter of 2004, compared with the same quarter of 2003, resulted from increased nuclear generation - 23%. Purchased power costs increased by $6 million reflecting higher unit costs which were partially offset by lower kilowatt-hour purchases due to the decreased requirements for retail generation sales. Lower nuclear operating costs occurred in large part due to the absence of the Beaver Valley Unit 1 (100% ownership) outage that occurred in the first quarter of 2003. The decrease in other operating costs reflects in part lower employee benefit costs. Charges for depreciation and amortization increased by $16 million in the first quarter of 2004 compared to the first quarter of 2003 primarily from two factors - increased amortization of the Ohio transition regulatory assets ($14 million) and lower shopping incentive deferrals ($1 million), partially offset by increased regulatory asset deferrals of $2 million. Net Interest Charges Net interest charges continued to trend lower, decreasing by $8 million in the first quarter of 2004 from the same period last year, reflecting redemptions and refinancings since the first quarter of 2003. OE Companies' net debt redemptions totaled $55 million during the first quarter of 2004 and are expected to result in annualized savings of $4 million (excluding change in revolver facilities). 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 $32 million. The cumulative 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 million increase to income, or $32 million net of income taxes. Capital Resources and Liquidity ------------------------------- OE's cash requirements in 2004 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, 2004, OE had $1 million of cash and cash equivalents, compared with $2 million as of December 31, 2003. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided by operating activities during the first quarter of 2004, compared with the corresponding period in 2003 were as follows: 54 Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $230 $183 Working capital and other............ (115) (29) ------------------------------------------------------------- Total................................ $115 $154 ============================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash from operating activities decreased $39 million due to an $86 million increase in funds used for working capital -- that decrease was offset in part by a $47 million increase in cash earnings. The decrease from working capital and other changes primarily reflects the change in cash requirements for accounts payable to associated companies of $227 million and accrued taxes of $318 million for the first quarter of 2004 as compared to 2003. Both variances reflect offsetting changes of $249 million for the reallocation of tax liabilities between associated companies related to the tax sharing agreement. Cash Flows From Financing Activities In the first quarter of 2004, net cash used for financing activities decreased to $105 million from $265 million in the same period last year. The decrease resulted from increased short-term borrowings partially offset by an increase in common stock dividend payments to FirstEnergy. OE had approximately $618 million of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $199 million of short-term indebtedness as of March 31, 2004. Available borrowing capability under bilateral bank facilities totaled $159 million as of March 31, 2004. The OE Companies had the capability to issue $2.1 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds, although unsecured senior note indentures entered into by OE in 2003 limit its ability to issue secured debt, including FMB, subject to certain exceptions. Based upon applicable earnings coverage tests the OE Companies could issue up to $3.4 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2004. In October 2003, OE entered into a syndicated $125 million 364-day revolving credit facility and a syndicated $125 million three-year revolving credit facility. Combined with an existing syndicated $250 million two-year facility for OE, maturing in May 2005 and bank facilities of $34 million, OE's available credit facilities total $534 million, all of which were unused as of March 31, 2004. These facilities are intended to provide liquidity to meet the short-term working capital requirements of OE and its affiliates. Borrowings under these facilities are conditioned on OE maintaining compliance with certain financial covenants in the agreements. OE, under its $125 million 364-day and $250 million two-year facilities, is required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually-defined fixed charge coverage ratio of no less than 2 to 1. OE is in compliance with these financial covenants. The ability to draw on these facilities is also conditioned upon OE making certain representations and warranties to the lending banks prior to drawing on its facilities, including a representation that there has been no material adverse change in its business, its condition (financial or otherwise), its results of operations, or its prospects. OE's primary credit facilities do not contain provisions, whereby its ability to borrow would be restricted or denied, or repayment of outstanding loans under the facilities accelerated, as a result of any change in the credit ratings of OE by any of the nationally-recognized rating agencies. Borrowings under the primary facilities do contain "pricing grids", whereby the cost of funds borrowed under the facilities is related to the credit ratings of the company borrowing the funds. OE has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Available bank borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2004 was 1.30%. In March 2004, Penn completed an on-balance sheet, receivable financing transaction which allows it to borrow up to $25 million. The borrowing rate is based on bank commercial paper rates. Penn is required to pay an annual facility fee of 0.40% on the entire finance limit. The facility was undrawn as of March 31, 2004. This facility matures on March 29, 2005. 55 OE's access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of OE and FirstEnergy. The ratings outlook on all of its securities is stable. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy to restart the Davis-Besse nuclear plant was positive for credit quality because it would positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." Cash Flows From Investing Activities Net use of cash for investing activities totaled $11 million in the first quarter of 2004, compared to net cash provided by investing activities of $106 million for the same period of 2003. The $117 million changes in funds from investing activities resulted primarily from loan payments to associated companies, offset in part by lower capital expenditures. During the last three quarters of 2004, capital requirements for property additions and capital leases are expected to be about $183 million, including $46 million for nuclear fuel. OE has additional requirements of approximately $68 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. As of March 31, 2004, OE has $278 million in deposits pledged as collateral to secure reimbursement obligations related to certain letters of credit supporting OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits had previously been classified as a noncurrent asset in Other Property and Investments. OE expects to replace the cash collateralized LOC with a structure that would not require cash collateral. OE anticipates using the cash from the deposit to repay short term debt in the third quarter of 2004 and for other general corporate purposes. Off-Balance Sheet Arrangements ------------------------------ 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, 2004, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $706 million. Equity Price Risk ----------------- Included in OE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $218 million and $209 million as of March 31, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $22 million reduction in fair value as of March 31, 2004. 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. 56 Regulatory Matters Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Ohio Beginning on January 1, 2001, OE's customers were able to choose their electricity suppliers. Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's 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 for OE customers), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2005. As part of OE's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. OE is also required to provide 560 megawatts (MW) of low cost supply to unaffiliated alternative suppliers who 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. On October 21, 2003, the Ohio EUOC filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or 57 o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing OE's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service for OE's customers. Beginning in 2006, customers would pay market prices for generation as determined by the auction. Under the Rate Stabilization Plan option, customers would have price and supply stability through 2008 - three years beyond the end of the market development period - as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually to ensure that customers pay the lowest available prices; extension of our support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, OE is requesting: o Extension of the transition cost amortization period from 2006 to 2007; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. Oral arguments were held before the PUCO on April 21 and a decision is expected from the PUCO in the Spring of 2004. Pennsylvania In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. Penn is currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. On January 16, 2004, the PPUC initiated a formal investigation of whether Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Penn's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year end of 2004. Penn is unable to predict the outcome of the investigation or the impact of the PPUC order. Regulatory Assets- Regulatory assets are costs which have been authorized by the PUCO, PPUC and the FERC, for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. 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 plans. The OE Companies' regulatory assets are as follows: Regulatory Assets as of --------------------------------------------------------- March 31, December 31, Company 2004 2003 --------------------------------------------------------- (In millions) OE......................... $1,348 $1,450 Penn....................... 15 28 --------------------------------------------------------- Consolidated Total...... $1,363 $1,478 =================================================================== 58 Environmental Matters Various federal, state and local authorities regulate OE with regard to air and water quality and other environmental matters. 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 OE's earnings and competitive position to the extent that 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. Overall, OE believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. OE is required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. 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. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. 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. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on the OE Companies' financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of March 31, 2004. The OE Companies are complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments 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 OE Companies' 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 (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the NOx budgets at the OE Companies' Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires compliance with the NOx budgets at the OE Companies' Ohio facilities by May 31, 2004. The OE Companies' facilities have complied with the NOx budgets in 2003 and 2004, respectively. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. -Canada Power System Outage Task Force released its final report on this outage. The final report supercedes the interim report that had been issued in November, 2003. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including, an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's 59 system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has undertaken several initiatives, some prior to and some since the August 14th power outage, to enhance reliability which are consistent with these and other recommendations and believes it will complete those relating to summer 2004 by June 30 (see Regulatory Matters above). As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Legal Matters Legal proceedings have been filed against FirstEnergy in connection with, among other things, the restatements in August 2003 by FirstEnergy and its Ohio utility subsidiaries of previously reported results, the August 14th power outage described above, and the extended outage at the Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the issues raised include alleged violations of federal securities laws, breaches of fiduciary duties under state law by FirstEnergy directors and officers, and damages as a result of one or more of the noted events. The securities cases have been consolidated into one action pending in federal court in Akron, Ohio. The derivative actions filed in federal court likewise have been consolidated as a separate matter, also in federal court in Akron. There also are pending derivative actions in state court. FirstEnergy's Ohio utility subsidiaries were also named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14th power outage. FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be instituted against them. In particular, if FirstEnergy were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on its financial condition and results of operations. Various lawsuits, claims and proceedings related to OE's normal business operations are pending against OE, the most significant of which are described above. Critical Accounting Policies ---------------------------- OE prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of the OE Companies' assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. The OE Companies' more significant accounting policies are described below. Regulatory Accounting The OE Companies are subject to regulation that sets the prices (rates) they are permitted to charge their customers based on 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 - $1.4 billion as of March 31, 2004. 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 electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided from alternative suppliers. 60 Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions 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 in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 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. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% 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. Ohio Transition Cost Amortization In connection with FirstEnergy's transition plan, the PUCO determined allowable transition costs based on amounts recorded on OE's regulatory books. These costs exceeded those deferred or capitalized on OE's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred. OE uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for OE. In computing the transition cost amortization, OE includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, the OE Companies periodically evaluate their long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might 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 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). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. 61 Nuclear Decommissioning In accordance with SFAS 143, the OE Companies recognize an ARO for the future decommissioning of their nuclear power plants. The ARO liability represents an estimate of the fair value of the OE Companies' current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. The OE Companies used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. New Accounting Standards and Interpretations -------------------------------------------- FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, OE adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on OE's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. 62 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31, -------------------------- 2004 2003 --------- -------- (In thousands) OPERATING REVENUES.............................................................. $ 426,535 $ 419,771 ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 17,196 13,769 Purchased power.............................................................. 134,677 136,345 Nuclear operating costs...................................................... 32,715 55,361 Other operating costs........................................................ 64,027 61,899 ---------- ---------- Total operation and maintenance expenses................................. 248,615 267,374 Provision for depreciation and amortization.................................. 61,776 51,357 General taxes................................................................ 38,818 39,713 Income taxes................................................................. 4,013 7,316 ---------- ---------- Total operating expenses and taxes....................................... 353,222 365,760 ---------- ---------- OPERATING INCOME................................................................ 73,313 54,011 OTHER INCOME.................................................................... 11,727 4,741 ---------- ---------- INCOME BEFORE NET INTEREST CHARGES.............................................. 85,040 58,752 ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt................................................... 32,211 40,640 Allowance for borrowed funds used during construction........................ (1,711) (2,167) Other interest expense....................................................... 6,065 31 Subsidiary's preferred dividend requirements................................. -- 4,950 ---------- ---------- Net interest charges..................................................... 36,565 43,454 ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 48,475 15,298 Cumulative effect of accounting change (Net of income taxes of $30,168,000) (Note 2)...................................................... -- 42,378 ---------- ---------- NET INCOME...................................................................... 48,475 57,676 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 1,744 (759) ---------- ----------- EARNINGS ON COMMON STOCK........................................................ $ 46,731 $ 58,435 ========== ========== The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements. 63
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2004 2003 ---------------------------- (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $4,334,014 $4,232,335 Less-Accumulated provision for depreciation.................................... 1,880,144 1,857,588 ----------- ---------- 2,453,870 2,374,747 ---------- ---------- Construction work in progress- Electric plant............................................................... 95,271 159,897 Nuclear fuel................................................................. -- 21,338 ---------- ---------- 95,271 181,235 ---------- ---------- 2,549,141 2,555,982 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Investment in lessor notes..................................................... 584,950 605,915 Nuclear plant decommissioning trusts........................................... 332,303 313,621 Long-term notes receivable from associated companies........................... 97,212 107,946 Other.......................................................................... 17,818 23,636 ---------- ---------- 1,032,283 1,051,118 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 200 24,782 Receivables- Customers.................................................................... 8,784 10,313 Associated companies......................................................... 43,741 40,541 Other (less accumulated provisions of $1,454,000 and $1,765,000, respectively, for uncollectible accounts)................................................ 39,742 185,179 Notes receivable from associated companies..................................... 14,138 482 Materials and supplies, at average cost........................................ 52,971 50,616 Prepayments and other.......................................................... 2,616 4,511 ---------- ---------- 162,192 316,424 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 1,021,972 1,056,050 Goodwill....................................................................... 1,693,629 1,693,629 Property taxes................................................................. 77,122 77,122 Other.......................................................................... 23,599 23,123 ---------- ---------- 2,816,322 2,849,924 ---------- ---------- $6,559,938 $6,773,448 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stockholder's equity - Common stock, without par value, authorized 105,000,000 shares - 79,590,689 shares outstanding.............................................. $1,281,962 $1,281,962 Accumulated other comprehensive income....................................... 7,405 2,653 Retained earnings............................................................ 485,944 494,212 ---------- ---------- Total common stockholder's equity........................................ 1,775,311 1,778,827 Preferred stock not subject to mandatory redemption............................ 96,404 96,404 Long-term debt and other long-term obligations................................. 1,954,569 1,884,643 ---------- ---------- 3,826,284 3,759,874 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock........................... 379,924 387,414 Accounts payable- Associated companies......................................................... 268,045 245,815 Other........................................................................ 7,499 7,342 Notes payable to associated companies.......................................... 16,203 188,156 Accrued taxes................................................................. 134,596 202,522 Accrued interest............................................................... 46,111 37,872 Lease market valuation liability............................................... 60,200 60,200 Other.......................................................................... 33,337 76,722 ---------- ---------- 945,915 1,206,043 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes.............................................. 485,976 486,048 Accumulated deferred investment tax credits.................................... 64,750 65,996 Asset retirement obligation.................................................... 259,049 254,834 Retirement benefits............................................................ 110,833 105,101 Lease market valuation liability............................................... 713,400 728,400 Other.......................................................................... 153,731 167,152 ---------- ---------- 1,787,739 1,807,531 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................ ---------- ---------- $6,559,938 $6,773,448 ========== ========== The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these balance sheets. 64
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, ---------------------------- 2004 2003 --------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 48,475 $ 57,676 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization.............................. 61,776 51,357 Nuclear fuel and capital lease amortization.............................. 5,107 5,044 Other amortization....................................................... (4,723) (4,613) Deferred operating lease costs, net...................................... (41,635) (41,603) Deferred income taxes, net............................................... (2,793) 33,804 Amortization of investment tax credits................................... (1,246) (1,202) Accrued retirement benefit obligations................................... 5,732 1,797 Accrued compensation, net................................................ 1,453 2,580 Cumulative effect of accounting change (Note 2).......................... -- (72,547) Receivables.............................................................. 143,766 15,242 Materials and supplies................................................... (2,355) (128) Accounts payable......................................................... 22,387 (44,129) Accrued taxes............................................................ (67,926) 2,896 Accrued interest......................................................... 8,239 8,844 Prepayments and other current assets..................................... 1,895 1,772 Other.................................................................... (18,362) (11,970) --------- --------- Net cash provided from operating activities............................ 159,790 4,820 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt............................................................. 80,967 -- Short-term borrowings, net................................................. -- 33,245 Redemptions and Repayments- Long-term debt............................................................. (7,985) (45,103) Short-term borrowings, net................................................. (182,167) -- Dividend Payments- Common stock............................................................... (55,000) -- Preferred stock............................................................ (1,744) (1,865) --------- --------- Net cash used for financing activities................................. (165,929) (13,723) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (17,868) (31,218) Loans to associated companies, net........................................... (2,922) -- Investments in lessor notes.................................................. 20,965 19,071 Contributions to nuclear decommissioning trusts.............................. (7,256) (7,256) Other........................................................................ (11,362) (1,250) --------- --------- Net cash used for investing activities................................. (18,443) (20,653) --------- --------- Net decrease in cash and cash equivalents....................................... (24,582) (29,556) Cash and cash equivalents at beginning of period ............................... 24,782 30,382 --------- --------- Cash and cash equivalents at end of period...................................... $ 200 $ 826 ========= ========= The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements. 65
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, 2004, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2004 and 2003. 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, 2003, 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 (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(F) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated February 25, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, 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 7, 2004 66 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI 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 2004 decreased to $47 million from $58 million in the first quarter of 2003. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $42 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect increased to $48 million in the first quarter of 2004 from $15 million in the first quarter of 2003. Operating revenues increased by $7 million or 1.6% in the first quarter of 2004 from the same period in 2003. Higher revenues resulted from a $14 million (18.3%) increase in wholesale sales partially offset by a decrease in kilowatt-hour sales to retail customers. The increase in wholesale sales revenues (primarily to FES) was due to increased fossil generation (at the Mansfield Plant) available for sale to FES. Electric generation services provided by alternative suppliers as a percent of total sales deliveries in CEI's franchise area increased to 42.5% in the first quarter of 2004 from 38.0% in the first quarter of 2003, resulting in a 4.8% decrease in generation retail sales and reducing generation sales revenue by $4 million. Distribution deliveries increased 2.6% in the first quarter of 2004 compared to the corresponding quarter of 2003, with increases in all customer sectors (residential, commercial and industrial). The $5 million decrease in revenues from electricity throughput in the first quarter of 2004 from the same quarter of the prior year was due to lower composite prices, offsetting the effect of the higher distribution deliveries. Under the Ohio transition plan, CEI provides incentives to customers to encourage switching to alternative energy providers. These revenue reductions are deferred for future recovery under the transition plan and do not materially affect current period earnings. The change in shopping customer sales by class (resulting in lower composite prices in 2004 compared to 2003) offset the effect of increased shopping levels and resulted in a $3 million revenue increase. Changes in electric generation sales and distribution deliveries in the first quarter of 2004 from the first quarter of 2003 are summarized in the following table: Changes in Kilowatt-Hour Sales --------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. (4.8)% Wholesale............................... 10.0% --------------------------------------------------- Total Electric Generation Sales........... 2.3% =================================================== Distribution Deliveries: Residential............................. 1.3% Commercial.............................. 0.9% Industrial.............................. 4.5% --------------------------------------------------- Total Distribution Deliveries............. 2.6% =================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $13 million in the first quarter of 2004 from the first quarter of 2003. The following table presents changes from the prior year by expense category. 67 Operating Expenses and Taxes - Changes ---------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................. $ 3 Purchased power ................................. (1) Nuclear operating costs.......................... (23) Other operating costs............................ 2 ------------------------------------------------------------ Total operation and maintenance expenses....... (19) Provision for depreciation and amortization...... 10 General taxes.................................... (1) Income taxes..................................... (3) ------------------------------------------------------------- Total operating expenses and taxes............. $(13) ============================================================= Higher fuel costs in the first quarter of 2004, compared with the first quarter of 2003, primarily resulted from increased fossil generation (up 64%). Lower purchased power costs reflect reduced kilowatt-hours purchased offset in part by higher unit costs. Reductions in nuclear operating costs in the first quarter of 2004, compared with the first quarter of 2003 were primarily due to the reduction in incremental costs associated with the Davis-Besse outage (see Davis-Besse Restoration). The increase in other operating costs resulted in part from higher employee benefit costs. The increase in depreciation and amortization charges in the first quarter of 2004, compared with the first quarter of 2003, was primarily due to increased amortization of regulatory assets ($6 million) and lower shopping incentive deferrals ($3 million). Income taxes in the first quarter of 2004 included credits from the favorable resolution of certain tax matters that had been reserved in prior periods, thus reducing CEI's reported effective income tax rate. Other Income The increase in other income was principally due to approximately $7 million of interest income from Shippingport which was consolidated into CEI as of December 31, 2003. Net Interest Charges Net interest charges continued to trend lower, decreasing by $7 million in the first quarter of 2004 from the same quarter last year, reflecting redemptions and refinancings since the end of the first quarter of 2003. CEI's long-term debt redemptions of $8 million during the first quarter of 2004 are expected to result in annualized savings of approximately $700,000. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, CEI recorded an after-tax credit to net income of $42 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 resulted in a $73 million increase to income, or $42 million net of income taxes. Preferred Stock Dividend Requirements Preferred stock dividend requirements increased $3 million in the first quarter of 2004, compared to the same period last year, due to an adjustment that reduced costs in the first quarter of 2003. Capital Resources and Liquidity ------------------------------- CEI's cash requirements in 2004 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, 2004, CEI had $200,000 of cash and cash equivalents, compared with $25 million as of December 31, 2003 which included a portion of the NRG settlement claim sold in January 2004. The major sources for changes in these balances are summarized below. 68 Cash Flows From Operating Activities Cash provided from operating activities during the first quarter of 2004, compared with the first quarter of 2003 were as follows: Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 72 $ 32 Working capital and other............ 88 (27) ------------------------------------------------------------- Total................................ $160 $ 5 ============================================================= (1) Includes net income, depreciation and amortization, deferred operating lease costs, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities increased $155 million in the first quarter of 2004 from the first quarter of 2003 as a result of a $115 million increase from working capital and other changes and a $40 million increase in cash earnings. The largest factor contributing to the change in working capital was receiving the proceeds from the settlement of CEI's claim against NRG, Inc. for the terminated sale of four power plants. Cash Flows From Financing Activities Net cash used for financing activities increased $152 million in the first quarter of 2004 from the first quarter of 2003. The increase in funds used for financing activities was the result of a $215 million net increase in short-term borrowing repayments and a $55 million increase in common stock dividends, partially offset by new financings of $81 million and reduced security redemptions. CEI had about $14 million of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $16 million of short-term indebtedness as of March 31, 2004. CEI had the capability to issue $1.1 billion of additional first mortgage bonds on the basis of property additions and retired bonds. CEI has no restrictions on the issuance of preferred stock. CEI has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2004 was 1.30%. CEI's access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. The ratings outlook on all of its securities is stable. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy to restart the Davis-Besse nuclear plant was positive for credit quality because it would positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." Cash Flows From Investing Activities Net cash used for investing activities decreased $2 million in the first quarter of 2004 from the first quarter of 2003 and was primarily due to lower capital expenditures. 69 During the last three quarters of 2004, capital requirements for property additions are expected to be about $106 million, including $27 million for nuclear fuel. CEI has additional requirements of approximately $281 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. Off-Balance Sheet Arrangements ------------------------------ 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, 2004, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $109 million. CEI sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $132 million of off-balance sheet financing as of March 31, 2004. As of March 31, 2004, off-balance sheet arrangements include certain statutory business trusts created by CEI to issue trust preferred securities in the amount of $100 million. These trusts were included in the consolidated financial statements of FirstEnergy prior to the adoption of FIN 46R effective December 31, 2003, but have subsequently been deconsolidated under FIN 46R (see Note 2 - Variable Interest Entities). The deconsolidation under FIN 46R did not result in any change in outstanding debt. Equity Price Risk ----------------- Included in CEI's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $202 million and $188 million as of March 31, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $20 million reduction in fair value as of March 31, 2004. 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 system, which remains regulated. Customer rates were restructured into separate components to support customer choice. 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 FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. CEI's regulatory assets as of March 31, 2004 and December 2003 were $1.02 billion and $1.06 billion, respectively. All of CEI's regulatory assets are expected to continue to be recovered under the provisions of the transition plan. As part of CEI's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. CEI is also required to provide 400 MW of low cost supply to unaffiliated alternative suppliers who 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. On October 21, 2003, the Ohio EUOC filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or 70 o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing CEI's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service for CEI's customers. Beginning in 2006, customers would pay market prices for generation as determined by the auction. Under the Rate Stabilization Plan option, customers would have price and supply stability through 2008 - three years beyond the end of the market development period - as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually to ensure that customers pay the lowest available prices; extension of CEI's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, CEI is requesting: o Extension of the transition cost amortization period from 2008 to mid-2009; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. Oral arguments were held before the PUCO on April 21 and a decision is expected from the PUCO in the Spring of 2004. Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures. 71 With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Davis-Besse Restoration On April 30, 2002, the NRC initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process was 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. This process led to the NRC's March 8, 2004 approval of Davis-Besse's restart. Restart activities included both hardware and management issues. In addition to refurbishment and installation work at the plant, FENOC made significant management and human performance changes with the intent of enhancing the proper safety culture throughout the workforce. The focus of activities in the first quarter of 2004 involved management and human performance issues. As a result, incremental maintenance costs declined in the first quarter of 2004 compared to the same period in 2003 as emphasis shifted to performance issues; however, replacement power costs were higher in the first quarter of 2004. The plant's generating equipment was tested in March in preparation for resumption of operation. On April 4, 2004, Davis-Besse resumed generating electricity at 100% power. Incremental costs associated with the extended Davis-Besse outage (CEI's share - 51.38%) for the first quarter of 2004 and 2003 were as follows: Three Months Ended March 31, ------------------ Increase Costs of Davis-Besse Extended Outage 2004 2003 (Decrease) -------------------------------------------------------------------------------- (In millions) Incremental Expense Replacement power................. $64 $52 $ 12 Maintenance....................... 1 36 (35) -------------------------------------------------------------------------------- Total......................... $65 $88 $(23) ================================================================================ Incremental Net of Tax Expense...... $38 $52 $(14) ================================================================================ Environmental Matters Various federal, state and local authorities regulate CEI with regard to air and water quality and other environmental matters. 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 CEI's earnings and competitive position to the extent that 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. Overall, CEI believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. CEI is required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. CEI cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. CEI is complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments 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 CEI's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the NOx budgets at CEI's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires compliance with the NOx budgets at CEI's Ohio facilities by May 31, 2004. CEI's facilities have complied with the NOx budgets in 2003 and 2004, respectively. 72 CEI has been named as a 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, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, CEI's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. CEI has accrued liabilities aggregating approximately $2.4 million as of March 31, 2004. CEI accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in CEI's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. -Canada Power System Outage Task Force released its final report on this outage. The final report supercedes the interim report that had been issued in November, 2003. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including, an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has undertaken several initiatives, some prior to and some since the August 14th power outage, to enhance reliability which are consistent with these and other recommendations and believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives above). As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. 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 herein. FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse plant. FirstEnergy is unable to predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002. Further, a petition was filed with the NRC on March 29, 2004 by a group objecting to the NRC's restart order of the Davis-Besse Nuclear Power Station. The Petition seeks among other things, suspension of the Davis-Besse operating license. If it were ultimately determined that FirstEnergy has legal liability or is otherwise made subject to enforcement action based on any of the above matters with respect to the Davis-Besse outage, it could have a material adverse effect on CEI's financial condition and results of operations. Legal proceedings have been filed against FirstEnergy in connection with, among other things, the restatements in August 2003 by FirstEnergy and its Ohio utility subsidiaries of previously reported results, the August 14th power outage described above, and the extended outage at the Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the issues raised include alleged violations of federal securities laws, breaches of fiduciary duties under state law by FirstEnergy directors and officers, and damages as a result of one or more of the noted events. The securities cases have been consolidated into one action pending in federal court in Akron, Ohio. The derivative actions filed in federal court likewise have been consolidated as a separate matter, also in federal court in Akron. There are also pending derivative actions in state court. 73 FirstEnergy's Ohio utility subsidiaries were also named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14th power outage. FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be instituted against them. In particular, if FirstEnergy were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on CEI's financial condition and results of operations. Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. Critical Accounting Policies CEI prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect 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 these specific factors. CEI's more significant accounting policies are described below. Regulatory Accounting CEI is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on 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 - $1.02 billion as of March 31, 2004. 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 electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond 74 yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 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. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% 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. Ohio Transition Cost Amortization In connection with FirstEnergy's transition plan, the PUCO determined allowable transition costs based on amounts recorded on CEI's regulatory books. These costs exceeded those deferred or capitalized on CEI's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). CEI uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for CEI. In computing the transition cost amortization, CEI includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, CEI periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might 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 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). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, CEI recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of CEI's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. CEI used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. 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 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), the goodwill is tested for impairment. If impairment were to be indicated CEI would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. CEI's annual review was completed in the third quarter of 2003, with no impairment of goodwill indicated. 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 CEI's future evaluations of goodwill. As of March 31, 2004, CEI had $1.7 billion of goodwill. 75 New Accounting Standards and Interpretations -------------------------------------------- FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, CEI adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on CEI's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. 76 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31, ------------------------- 2004 2003 -------- -------- Restated (See Note 2) (In thousands) OPERATING REVENUES.............................................................. $235,398 $231,822 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 10,214 8,406 Purchased power.............................................................. 82,408 74,251 Nuclear operating costs...................................................... 42,692 64,555 Other operating costs........................................................ 36,208 32,932 -------- -------- Total operation and maintenance expenses................................. 171,522 180,144 Provision for depreciation and amortization.................................. 40,689 35,640 General taxes................................................................ 14,300 15,008 Income taxes (benefit)....................................................... (1,578) (4,291) -------- -------- Total operating expenses and taxes....................................... 224,933 226,501 -------- -------- OPERATING INCOME................................................................ 10,465 5,321 -------- -------- OTHER INCOME.................................................................... 5,833 3,100 -------- -------- INCOME BEFORE NET INTEREST CHARGES.............................................. 16,298 8,421 -------- -------- NET INTEREST CHARGES: Interest on long-term debt................................................... 9,461 10,888 Allowance for borrowed funds used during construction........................ (1,400) (1,306) Other interest expense (credit).............................................. 706 (532) -------- -------- Net interest charges..................................................... 8,767 9,050 -------- -------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................... 7,531 (629) Cumulative effect of accounting change (net of income taxes of $18,201,000) (Note 2)..................................................... -- 25,550 -------- -------- NET INCOME...................................................................... 7,531 24,921 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 2,211 2,205 -------- -------- EARNINGS ON COMMON STOCK........................................................ $ 5,320 $ 22,716 ======== ======== The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. 77
THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2004 2003 ------------------------------ (In thousands) ASSETS UTILITY PLANT: In service.................................................................... $1,801,162 $1,714,870 Less-Accumulated provision for depreciation................................... 733,161 721,754 ---------- ---------- 1,068,001 993,116 ---------- ---------- Construction work in progress- Electric plant.............................................................. 66,499 125,051 Nuclear fuel................................................................ -- 20,189 ---------- ---------- 66,499 145,240 ---------- ---------- 1,134,500 1,138,356 OTHER PROPERTY AND INVESTMENTS: Investment in lessor notes.................................................... 190,658 200,938 Nuclear plant decommissioning trusts.......................................... 255,996 240,634 Long-term notes receivable from associated companies.......................... 163,961 163,626 Other......................................................................... 2,326 2,119 ---------- ---------- 612,941 607,317 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents..................................................... 16 2,237 Receivables- Customers................................................................... 4,876 4,083 Associated companies........................................................ 21,982 29,158 Other....................................................................... 734 14,386 Notes receivable from associated companies.................................... 16,376 19,316 Materials and supplies, at average cost....................................... 36,581 35,147 Prepayments and other........................................................ 3,320 6,704 ---------- ---------- 83,885 111,031 ---------- ---------- DEFERRED CHARGES: Regulatory assets............................................................. 432,399 459,040 Goodwill...................................................................... 504,522 504,522 Property taxes................................................................ 24,443 24,443 Other......................................................................... 10,902 10,689 ---------- ---------- 972,266 998,694 ---------- ---------- $2,803,592 $2,855,398 ========== ========== 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 income...................................... 15,023 11,672 Retained earnings........................................................... 118,940 113,620 ---------- ---------- Total common stockholder's equity......................................... 758,192 749,521 Preferred stock not subject to mandatory redemption........................... 126,000 126,000 Long-term debt................................................................ 274,595 270,072 ---------- ---------- 1,158,787 1,145,593 CURRENT LIABILITIES: Currently payable long-term debt.............................................. 335,950 283,650 Short-term borrowings......................................................... -- 70,000 Accounts payable- Associated companies........................................................ 126,835 132,876 Other....................................................................... 2,784 2,816 Notes payable to associated companies......................................... 262,654 285,953 Accrued taxes................................................................ 41,518 55,604 Accrued interest.............................................................. 10,132 12,412 Lease market valuation liability.............................................. 24,600 24,600 Other......................................................................... 46,771 37,299 ---------- ---------- 851,244 905,210 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes............................................. 204,108 201,954 Accumulated deferred investment tax credits................................... 26,668 27,200 Retirement benefits........................................................... 49,291 47,006 Asset retirement obligation................................................... 184,882 181,839 Lease market valuation liability.............................................. 286,450 292,600 Other......................................................................... 42,162 53,996 ---------- ---------- 793,561 804,595 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)............................... ---------- ---------- $2,803,592 $2,855,398 ========== ========== The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets. 78
THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, -------------------------- 2004 2003 -------- -------- Restated (See Note 2) (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 7,531 $ 24,921 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization.............................. 40,689 35,640 Nuclear fuel and capital lease amortization.............................. 5,506 2,768 Deferred operating lease costs, net...................................... (7,692) (7,672) Deferred income taxes, net............................................... (1,499) 19,130 Amortization of investment tax credits................................... (532) (514) Accrued retirement benefit obligation.................................... 2,285 771 Accrued compensation, net................................................ (733) (1,865) Cumulative effect of accounting change (Note 2).......................... -- (43,751) Receivables.............................................................. 20,035 12,249 Materials and supplies................................................... (1,434) (727) Accounts payable......................................................... (6,074) (53,917) Accrued taxes............................................................ (14,085) 6,281 Accrued interest......................................................... (2,280) (2,326) Prepayments and other current assets..................................... 3,384 (5,121) Other.................................................................... 79 (15,438) -------- -------- Net cash provided from (used for) operating activities................. 45,180 (29,571) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt............................................................. 73,000 -- Short-term borrowings, net................................................. -- 98,392 Redemptions and Repayments- Long-term debt............................................................. (15,000) (73,600) Short-term borrowings, net................................................. (93,299) -- Dividend Payments- Preferred stock............................................................ (2,211) (2,211) -------- -------- Net cash provided from (used for) financing activities................. (37,510) 22,581 -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (8,440) (17,622) Loans from (to) associated companies, net.................................... 2,606 (4,445) Investment in lessor notes................................................... 10,280 17,628 Contributions to nuclear decommissioning trust............................... (7,135) (7,135) Other........................................................................ (7,202) (679) -------- -------- Net cash used for investing activities................................. (9,891) (12,253) -------- -------- Net decrease in cash and equivalents............................................ (2,221) (19,243) Cash and cash equivalents at beginning of period................................ 2,237 20,688 -------- -------- Cash and cash equivalents at end of period...................................... $ 16 $ 1,445 ======== ======== The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. 79
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, 2004, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2004 and 2003. 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 2 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the three-month period ended March 31, 2003. 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, 2003, 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 (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(F) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated February 25, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, 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 7, 2004 80 THE TOLEDO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE conducts business in northwestern 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 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. Restatements of Previously Reported Quarterly Results ----------------------------------------------------- As discussed in Note 2 to the Consolidated Financial Statements, TE's quarterly results for the first quarter of 2003 have been restated to correct the amounts reported for operating expenses and interest charges. TE's costs which were originally recorded as operating expenses and should have been capitalized to construction were $0.4 million ($0.2 million after-tax), in the first quarter of 2003. In addition, TE's interest expense was overstated by $0.9 million ($0.5 million after-tax) in the first quarter of 2003. The impact of these adjustments was not material to TE's Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003. Results of Operations --------------------- Earnings on common stock in the first quarter of 2004 decreased to $5 million from $23 million in the first quarter of 2003. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $26 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect increased to $8 million in the first quarter of 2004 from a loss of $629,000 in the first quarter of 2003. Operating revenues increased by $4 million or 1.5% in the first quarter of 2004 from the same period in 2003. Higher revenues resulted from an $11 million (20.3%) increase in wholesale sales partially offset by a decrease in retail sales revenues. The increase in sales revenues from wholesale customers (primarily to FES) was due to increased fossil generation (at the Mansfield Plant) available for sale to FES. Electric generation services provided by alternative suppliers as a percent of total sales delivered in TE's franchise area increased to 23.7% in the first quarter of 2004 from 22% in the first quarter of 2003, resulting in a 4.0% decrease in TE's retail generation sales and a $3 million reduction in revenues. Distribution deliveries decreased 1.8% in the first quarter of 2004 compared to the corresponding quarter of 2003, with an increase in the industrial customer sector more than offset by reductions in the residential and commercial customer sectors. The $3 million decrease in revenues from electricity throughput in the first quarter of 2004 from the same quarter of the prior year was due to lower composite prices and reduced distribution deliveries. Under the Ohio transition plan, TE provides incentives to customers to encourage switching to alternative energy providers. These revenue reductions are deferred for future recovery under the transition plan and do not materially affect current period earnings. The change in revenue from shopping credits was relatively flat in the first quarter of 2004 compared with the corresponding period of 2003. Changes in electric generation sales and distribution deliveries in the first quarter of 2004 from the first quarter of 2003 are summarized in the following table: Changes in Kilowatt-Hour Sales ---------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (4.0)% Wholesale............................. 21.9% ---------------------------------------------------- Total Electric Generation Sales........... 6.5% ==================================================== Distribution Deliveries: Residential............................. (5.0)% Commercial.............................. (3.6)% Industrial.............................. 1.2% ---------------------------------------------------- Total Distribution Deliveries............. (1.8)% ==================================================== 81 Operating Expenses and Taxes Total operating expenses and taxes decreased by $2 million in the first quarter of 2004 from the first quarter of 2003. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes ----------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................. $ 2 Purchased power.................................. 8 Nuclear operating costs.......................... (22) Other operating costs............................ 3 ------------------------------------------------------------ Total operation and maintenance expenses....... (9) Provision for depreciation and amortization...... 5 General taxes.................................... (1) Income taxes..................................... 3 ------------------------------------------------------------ Total operating expenses and taxes............. $(2) ============================================================= Higher fuel costs in the first quarter of 2004, compared with the first quarter of 2003, primarily resulted from increased fossil generation (up 54%). Higher purchased power costs reflect additional kilowatt-hours purchased and higher unit costs. Reductions in nuclear operating costs in the first quarter of 2004, compared with the first quarter of 2003, were primarily due to the reduction in incremental costs associated with the Davis-Besse outage (see Davis-Besse Restoration). The increase in other operating costs resulted from higher energy delivery costs related to increased tree trimming activities. The increase in depreciation and amortization charges of $5 million in the first quarter of 2004, compared with the first quarter of 2003, was primarily due to increased amortization of regulatory assets. Other Income Other income increased by $3 million in the first quarter of 2004 compared to the same period of 2003 primarily due to the absence of 2003 costs related to closing Acme in Toledo, Ohio. Net Interest Charges Net interest charges continued to trend lower, decreasing by $283,000 in the first quarter of 2004 from the same quarter last year, reflecting redemptions and refinancings since the end of the first quarter of 2003. TE's long-term debt redemptions of $15 million during the first quarter of 2004 are expected to result in annualized savings of approximately $1 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 $26 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 $44 million increase to income, or $26 million net of income taxes. Capital Resources and Liquidity ------------------------------- TE's cash requirements in 2004 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, 2004, TE had approximately $16,000 of cash and cash equivalents, compared with $2 million as of December 31, 2003. 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 2004, compared with the first quarter of 2003 were as follows: 82 Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 45 $ 29 Working capital and other............ -- (59) ------------------------------------------------------------- Total................................ $45 $(30) ============================================================= (1) Includes net income, depreciation and amortization, deferred operating lease costs, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities increased $75 million in the first quarter of 2004 from the first quarter of 2003 as a result of a $59 million increase from working capital and other changes and a $16 million increase in cash earnings. The largest factor contributing to the change in working capital was a $48 million change in accounts payable. The increase from the change in working capital also included receiving $12 million in proceeds from the settlement of TE's claim against NRG, Inc. for the terminated sale of its Bay Shore Plant. Cash Flows From Financing Activities Net cash used for financing activities was $38 million in the first quarter of 2004 compared to $23 million provided from financing activities in the first quarter of 2003. The repayments and redemptions of debt in the first quarter of 2004 exceeded proceeds from issuing new long-term debt by $35 million. In the first quarter of 2003, short-term borrowings exceeded repayments of long-term debt by $25 million. TE had $16 million of cash and temporary investments (which include short-term notes receivable from associated companies) and $263 million of short-term indebtedness as of March 31, 2004. TE is currently precluded from issuing first mortgage bonds or preferred stock based upon applicable earnings coverage tests. TE has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2004 was 1.30%. TE's access to capital markets and costs of financing are dependent on the ratings of its securities and that of our holding company, FirstEnergy. The ratings outlook on all of its securities is stable. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy to restart the Davis-Besse nuclear plant was positive for credit quality because it would positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." Cash Flows From Investing Activities Net cash used for investing activities decreased $2 million in the first quarter of 2004 from the first quarter of 2003 and was primarily due to lower capital expenditures. During the last three quarters of 2004, capital requirements for property additions are expected to be about $42 million. TE has additional requirements of approximately $215 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. The cash requirements are expected to be satisfied from internal cash and short-term arrangements. 83 Off-Balance Sheet Arrangements ------------------------------ 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, 2004, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $595 million. TE sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $68 million of off-balance sheet financing as of March 31, 2004. Equity Price Risk ----------------- Included in TE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $156 million and $145 million as of March 31, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $16 million reduction in fair value as of March 31, 2004. 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 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 PUCO and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. TE's regulatory assets as of March 31, 2004 and December 2003 are $432 million and $459 million, respectively. All of TE's regulatory assets are expected to continue to be recovered under the provisions of the transition plan. 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 provide 160 megawatts (MW) of low cost supply to unaffiliated alternative suppliers who 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. On October 21, 2003, the Ohio EUOC filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing TE's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service for TE's customers. Beginning in 2006, customers would pay market prices for generation as determined by the auction. Under the Rate Stabilization Plan option, customers would have price and supply stability through 2008 - three years beyond the end of the market development period - as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be 84 conducted annually to ensure that customers pay the lowest available prices; extension of TE's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, TE is requesting: o Extension of the transition cost amortization period from mid-2007 to mid-2008; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. Oral arguments were held before the PUCO on April 21 and a decision is expected from the PUCO in the Spring of 2004. Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. 85 Davis-Besse Restoration On April 30, 2002, the NRC initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process was 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. This process led to the NRC's March 8, 2004 approval of Davis-Besse's restart. Restart activities included both hardware and management issues. In addition to refurbishment and installation work at the plant, FENOC made significant management and human performance changes with the intent of enhancing the proper safety culture throughout the workforce. The focus of activities in the first quarter of 2004 involved management and human performance issues. As a result, incremental maintenance costs declined in the first quarter of 2004 compared to the same period in 2003 as emphasis shifted to performance issues; however, replacement power costs were higher in the first quarter of 2004. The plant's generating equipment was tested in March in preparation for resumption of operation. On April 4, 2004, Davis-Besse resumed generating electricity at 100% power. Incremental costs associated with the extended Davis-Besse outage (TE's share - 48.62%) for the first quarter of 2004 and 2003 were as follows: Three Months Ended March 31, ------------------- Increase Costs of Davis-Besse Extended Outage 2004 2003 (Decrease) ------------------------------------------------------------------------------ (In millions) Incremental Expense Replacement power................. $64 $52 $ 12 Maintenance....................... 1 36 (35) ----------------------------------------------------------------------------- Total......................... $65 $88 $(23) ============================================================================= Incremental Net of Tax Expense...... $38 $52 $(14) ============================================================================== Environmental Matters Various federal, state and local authorities regulate TE with regard to air and water quality and other environmental matters. 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 TE's earnings and competitive position to the extent that 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. Overall, TE believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. TE is required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. TE cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. TE is complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments 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 TE's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the NOx budgets at TE's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires compliance with the NOx budgets at TE's Ohio facilities by May 31, 2004. TE's facilities have complied with the NOx budgets in 2003 and 2004, respectively. TE has been named as a 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, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, TE's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. TE has accrued liabilities aggregating 86 approximately $0.2 million as of March 31, 2004. TE accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in TE's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. -Canada Power System Outage Task Force released its final report on this outage. The final report supercedes the interim report that had been issued in November, 2003. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including, an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has undertaken several initiatives, some prior to and some since the August 14th power outage, to enhance reliability which are consistent with these and other recommendations and believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives above). As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. First Energy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Legal Matters Various lawsuits, claims and proceedings related to TE's normal business operations are pending against TE, the most significant of which are described herein. FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse plant. FirstEnergy is unable to predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis Besse outage in 2002. Further, a petition was filed with the NRC on March 29, 2004 by a group objecting to the NRC's restart order of the Davis-Besse Nuclear Power Station. The Petition seeks among other things, suspension of the Davis-Besse operating license. If it were ultimately determined that FirstEnergy has legal liability or is otherwise made subject to enforcement action based on any of the above matters with respect to the Davis-Besse outage, it could have a material adverse effect on TE's financial condition and results of operations. Legal proceedings have been filed against FirstEnergy in connection with, among other things, the restatements in August 2003 by FirstEnergy and its Ohio utility subsidiaries of previously reported results, the August 14th power outage described above, and the extended outage at the Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the issues raised include alleged violations of federal securities laws, breaches of fiduciary duties under state law by FirstEnergy directors and officers, and damages as a result of one or more of the noted events. The securities cases have been consolidated into one action pending in federal court in Akron, Ohio. The derivative actions filed in federal court likewise have been consolidated as a separate matter, also in federal court in Akron. There are also pending derivative actions in state court. FirstEnergy's Ohio utility subsidiaries were also named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14th power outage. FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be instituted against them. In particular, if FirstEnergy were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on TE's financial condition and results of operations. 87 Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. Critical Accounting Policies ---------------------------- TE prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect 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 these specific factors. TE's more significant accounting policies are described below. Regulatory Accounting TE is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on 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 - $432 million as of March 31, 2004. 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 electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 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. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets 88 based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% 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. Ohio Transition Cost Amortization In connection with FirstEnergy's transition plan, the PUCO determined allowable transition costs based on amounts recorded on TE's regulatory books. These costs exceeded those deferred or capitalized on TE's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). TE uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for TE. In computing the transition cost amortization, TE includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, TE periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might 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 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). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, TE recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of TE's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. TE used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. 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 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), the goodwill is tested for impairment. If impairment were to be indicated, TE would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. TE's annual review was completed in the third quarter of 2003, with no impairment of goodwill indicated. 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 TE's future evaluations of goodwill. As of March 31, 2004, TE had $505 million of goodwill. 89 New Accounting Standards and Interpretations FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, TE adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on TE's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. 90 PENNSYLVANIA POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31, ------------------------- 2004 2003 --------- -------- (In thousands) OPERATING REVENUES.............................................................. $142,623 $128,343 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 6,206 4,713 Purchased power.............................................................. 48,508 44,066 Nuclear operating costs...................................................... 18,623 46,929 Other operating costs........................................................ 13,685 16,550 -------- -------- Total operation and maintenance expenses................................. 87,022 112,258 Provision for depreciation and amortization.................................. 13,438 13,265 General taxes................................................................ 6,634 6,179 Income taxes (benefit)....................................................... 15,038 (1,479) -------- -------- Total operating expenses and taxes....................................... 122,132 130,223 -------- -------- OPERATING INCOME (LOSS)......................................................... 20,491 (1,880) OTHER INCOME.................................................................... 982 561 -------- -------- INCOME (LOSS) BEFORE NET INTEREST CHARGES....................................... 21,473 (1,319) -------- -------- NET INTEREST CHARGES: Interest expense............................................................. 2,725 4,064 Allowance for borrowed funds used during construction........................ (922) (629) -------- -------- Net interest charges..................................................... 1,803 3,435 -------- -------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................... 19,670 (4,754) Cumulative effect of accounting change (net of income taxes of $7,532,000) (Note 2) -- 10,618 -------- -------- NET INCOME...................................................................... 19,670 5,864 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 640 912 -------- -------- EARNINGS ON COMMON STOCK........................................................ $ 19,030 $ 4,952 ======== ======== The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements. 91
PENNSYLVANIA POWER COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2004 2003 --------------------------- (In thousands) ASSETS UTILITY PLANT: In service........................................................................ $820,643 $808,637 Less-Accumulated provision for depreciation....................................... 332,363 324,710 -------- -------- 488,280 483,927 -------- -------- Construction work in progress- Electric plant................................................................. 69,521 68,091 Nuclear fuel................................................................... 360 360 -------- -------- 69,881 68,451 -------- -------- 558,161 552,378 -------- -------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts ............................................. 137,840 133,867 Long-term notes receivable from associated companies.............................. 33,136 39,179 Other............................................................................. 836 2,195 -------- -------- 171,812 175,241 -------- -------- CURRENT ASSETS: Cash and cash equivalents......................................................... 40 40 Notes receivable from associated companies........................................ 6,558 399 Receivables- Customers (less accumulated provisions of $816,000 and $769,000, respectively, for uncollectible accounts).................................... 46,129 44,861 Associated companies........................................................... 24,492 24,965 Other.......................................................................... 466 1,047 Materials and supplies, at average cost........................................... 34,993 33,918 Prepayments....................................................................... 22,716 9,383 -------- -------- 135,394 114,613 -------- -------- DEFERRED CHARGES: Regulatory assets................................................................. 15,155 27,513 Other............................................................................. 9,348 9,634 -------- -------- 24,503 37,147 -------- -------- $889,870 $879,379 ======== ======== 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........................................... (11,783) (11,783) Retained earnings.............................................................. 65,209 54,179 -------- -------- Total common stockholder's equity.......................................... 241,816 230,786 Preferred stock not subject to mandatory redemption............................... 39,105 39,105 Long-term debt and other long-term obligations.................................... 130,397 130,358 -------- -------- 411,318 400,249 -------- -------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock.............................. 52,224 93,474 Accounts payable- Associated companies........................................................... 43,895 40,172 Other.......................................................................... 1,311 1,294 Notes payable to associated companies............................................. 40,418 11,334 Accrued taxes..................................................................... 35,900 27,091 Accrued interest.................................................................. 2,440 4,396 Other............................................................................. 9,557 8,444 -------- -------- 185,745 186,205 -------- -------- NONCURRENT LIABILITIES: Accumulated deferred income taxes................................................. 93,894 97,871 Accumulated deferred investment tax credits....................................... 3,443 3,516 Asset retirement obligation....................................................... 131,678 129,546 Retirement benefits............................................................... 55,830 54,057 Other............................................................................. 7,962 7,935 -------- -------- 292,807 292,925 -------- -------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................ -------- -------- $889,870 $879,379 ======== ======== The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets. 92
PENNSYLVANIA POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, --------------------------- 2004 2003 --------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 19,670 $ 5,864 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization................................ 13,438 13,265 Nuclear fuel and lease amortization........................................ 4,565 3,583 Deferred income taxes, net................................................. (1,231) 6,122 Amortization of investment tax credits..................................... (575) (620) Cumulative effect of accounting change (Note 2)............................ -- (18,150) Receivables................................................................ (214) 17,262 Materials and supplies..................................................... (1,075) (431) Accounts payable........................................................... 3,740 27,844 Accrued taxes.............................................................. 8,809 4,271 Accrued interest........................................................... (1,956) (2,009) Prepayments and other current assets....................................... (13,334) (16,288) Asset retirement obligation, net........................................... 3,195 (980) Other...................................................................... 3,237 600 -------- -------- Net cash provided from operating activities............................ 38,269 40,333 -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net................................................. 29,084 -- Redemptions and Repayments- Long-term debt............................................................. (42,302) (16) Dividend Payments- Common stock............................................................... (8,000) (13,000) Preferred stock............................................................ (640) (912) -------- -------- Net cash used for financing activities................................. (21,858) (13,928) -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (13,998) (31,054) Contributions to nuclear decommissioning trusts.............................. (399) (399) Loans from (to) associated companies, net.................................... (116) 4,921 Other........................................................................ (1,898) 732 -------- -------- Net cash used for investing activities................................. (16,411) (25,800) -------- -------- Net change in cash and cash equivalents......................................... -- 605 Cash and cash equivalents at beginning of period................................ 40 1,222 -------- -------- Cash and cash equivalents at end of period...................................... $ 40 $ 1,827 ======== ======== The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements. 93
REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Pennsylvania Power Company: We have reviewed the accompanying consolidated balance sheet of Pennsylvania Power Company and its subsidiary as of March 31, 2004, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2004 and 2003. 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 balance sheet and the statement of capitalization as of December 31, 2003, and the related 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 asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those financial statements) dated February 25, 2004, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 7, 2004 94 PENNSYLVANIA POWER COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Penn is a wholly owned, electric utility subsidiary of OE. Penn 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. Penn's wholly owned subsidiary, Penn Power Funding LLC, began operations on March 30, 2004. Results of Operations --------------------- Earnings on common stock in the first quarter of 2004 increased to $19 million from $5 million in the first quarter of 2003. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $11 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $20 million in the first three months of 2004, compared to a loss of $5 million for the same period of 2003. Improved results in the first quarter of 2004 reflect higher operating revenues and lower operating expenses -- primarily nuclear operating costs. Operating revenues increased by $14 million or 11.1% in the first quarter of 2004 compared with the same period in 2003. The higher revenues primarily resulted from increased wholesale revenues of $11 million due to increased nuclear generation available for sale to FES in the first quarter of 2004. Retail sales revenues increased $3 million primarily from a 3.1% increase in generation sales. Distribution deliveries increased 3.1% in the first quarter of 2004 compared with the corresponding quarter of 2003, with increases in all customer sectors. The change in revenues from electricity throughput was flat with the effect of the volume increase offset by lower composite prices. Changes in electric generation sales and distribution deliveries in the first quarter of 2004 from the same quarter of 2003 are summarized in the following table: Changes in Kilowatt-Hour Sales --------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. 3.1% Wholesale............................... 32.1% --------------------------------------------------- Total Electric Generation Sales........... 18.3% =================================================== Distribution Deliveries: Residential............................. 3.1% Commercial.............................. 0.5% Industrial.............................. 5.4% --------------------------------------------------- Total Distribution Deliveries............. 3.1% =================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $8 million in the first quarter of 2004 from the first quarter of 2003. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes ------------------------------------------------------------ Increase (Decrease) (In millions) Fuel............................................ $ 2 Purchased power ................................ 4 Nuclear operating costs......................... (28) Other operating costs........................... (3) ------------------------------------------------------------ Total operation and maintenance expenses..... (25) Provision for depreciation and amortization..... -- General taxes................................... -- Income taxes.................................... 17 ------------------------------------------------------------ Total operating expenses and taxes........... $ (8) ============================================================ Higher fuel costs in the first quarter of 2004, compared with the same quarter of 2003, resulted from increased nuclear generation. Purchased power costs were higher in the first three months of 2004 reflecting a 4.8% increase 95 in kilowatt-hour purchases and higher unit costs. Lower nuclear operating costs occurred in large part due to the absence in 2004 of a refueling outage at Beaver Valley Unit 1. Beaver Valley Unit 1 (65.00% ownership) experienced a refueling outage in the first quarter of 2003. Net Interest Charges Net interest charges continued to trend lower, decreasing by approximately $2 million in the first quarter of 2004 from the same period last year, reflecting mandatory and optional redemptions of $83 million total principal amount of debt securities since the first quarter of 2003. 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 $11 million. The cumulative 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 an $18 million increase to income, or $11 million net of income taxes. Capital Resources and Liquidity ------------------------------- Penn's cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing Penn'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, 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 Penn had $40,000 of cash and cash equivalents as of March 31, 2004 and December 31, 2003. Cash Flows From Operating Activities Cash provided from operating activities during the first quarter of 2004, compared with the corresponding period in 2003 were as follows: Operating Cash Flows 2004 2003 ----------------------------------------------------------------- (In millions) Cash earnings (1).................. $38 $11 Working capital and other.......... -- 29 ----------------------------------------------------------------- Total.............................. $38 $40 ================================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash from operating activities decreased to $38 million in the first quarter of 2004 from $40 million in the same period of 2003 due to a $27 million increase in cash earnings and a $29 million reduction from working capital and other changes (primarily change in accounts payable to associated companies). Cash Flows From Financing Activities In the first quarter of 2004, net cash used for financing activities increased to $22 million from $14 million in the same period last year. The increase resulted from increased long-term debt redemptions, partially offset by increased short-term borrowings and reduced common stock dividends to OE. Penn had approximately $7 million of cash and temporary investments (which include short-term notes receivable from associated companies) and $40 million of short-term indebtedness as of March 31, 2004. Penn may borrow from its affiliates on a short-term basis. Penn had the capability to issue $500 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 $521 million of preferred stock (assuming no additional debt was issued) as of March 31, 2004. In March 2004, Penn completed an on-balance sheet, receivable financing transaction which allows it to borrow up to $25 million. The borrowing rate is based on bank commercial paper rates. Penn is required to pay an annual facility fee of 0.40% on the entire finance limit. The facility was undrawn as of March 31, 2004. This facility matures on March 29, 2005. 96 Penn's access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of OE and FirstEnergy. The ratings outlook on all of its securities is stable. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy to restart the Davis-Besse nuclear plant was positive for credit quality because it would positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." Cash Flows From Investing Activities Net cash used for investing activities totaled $16 million in the first quarter of 2004, compared to $26 million for the same period of 2003. The $10 million decrease in funds used for investing activities resulted primarily from lower capital expenditures partially offset by changes in loans to associated companies. During the last three quarters of 2004, capital requirements for property additions and capital leases are expected to be about $70 million, including $21 million for nuclear fuel. Penn has additional requirements of approximately $22 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Equity Price Risk ----------------- Included in Penn's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $51 million and $50 million as of March 31, 2004 and December 31, 2003, 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, 2004. Outlook ------- Beginning in 1999, Penn's customers were able to select alternative energy suppliers. Penn continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. The PPUC authorized Penn'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. 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, which is referred to as its PLR obligation. Regulatory Matters 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 late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. Penn is currently awaiting the PPUC to issue a final order in both matters. The order 97 will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. On January 16, 2004, the PPUC initiated a formal investigation of whether Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Penn's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year end of 2004. Penn is unable to predict the outcome of the investigation or the impact of the PPUC order. Regulatory assets are costs which have been authorized by the PPUC and the FERC, for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of Penn's regulatory assets are expected to continue to be recovered under the provisions of its regulatory plan. Penn's regulatory assets totaled $15 million and $28 million as of March 31, 2004 and December 31, 2003, respectively. Environmental Matters Various federal, state and local authorities regulate Penn with regard to air and water quality and other environmental matters. 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 that 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. Overall, Penn believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. Penn is required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. Penn cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. 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. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on Penn's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of March 31, 2004. Penn is complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments 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 Penn's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the NOx budgets at Penn's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires compliance with the NOx budgets at Penn's Ohio facilities by May 31, 2004. Penn's facilities have complied with the NOx budgets in 2003 and 2004, respectively. 98 Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. -Canada Power System Outage Task Force released its final report on this outage. The final report supercedes the interim report that had been issued in November, 2003. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including, an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has undertaken several initiatives, some prior to and some since the August 14th power outage, to enhance reliability which are consistent with these and other recommendations and believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives below). As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. 99 With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Legal Matters Various lawsuits, claims and proceedings related to Penn's normal business operations are pending against Penn, the most significant of which are described above. Critical Accounting Policies Penn prepares its financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of Penn's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Penn's more significant accounting policies are described below. Regulatory Accounting Penn is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on 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. 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 electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 100 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. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% 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 144, Penn periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might 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 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). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, Penn recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of Penn's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Penn used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. New Accounting Standards and Interpretations -------------------------------------------- FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. Penn elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, Penn began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. 101 JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31, ------------------------- 2004 2003 --------- -------- Restated (See Note 2) (In thousands) OPERATING REVENUES.............................................................. $ 498,124 $ 656,952 --------- --------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 1,213 1,334 Purchased power.............................................................. 259,592 362,667 Other operating costs........................................................ 85,603 69,088 --------- --------- Total operation and maintenance expenses................................. 346,408 433,089 Provision for depreciation and amortization.................................. 94,701 96,973 General taxes................................................................ 15,932 15,812 Income taxes................................................................. 9,113 35,735 --------- --------- Total operating expenses and taxes....................................... 466,154 581,609 --------- --------- OPERATING INCOME................................................................ 31,970 75,343 OTHER INCOME.................................................................... 1,503 1,176 --------- --------- INCOME BEFORE NET INTEREST CHARGES.............................................. 33,473 76,519 --------- --------- NET INTEREST CHARGES: Interest on long-term debt................................................... 20,728 23,312 Allowance for borrowed funds used during construction........................ (120) (123) Deferred interest............................................................ (923) (3,202) Other interest expense (credit).............................................. 390 (159) Subsidiary's preferred stock dividend requirements........................... -- 2,674 --------- --------- Net interest charges..................................................... 20,075 22,502 --------- --------- NET INCOME...................................................................... 13,398 54,017 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 125 125 --------- --------- EARNINGS ON COMMON STOCK........................................................ $ 13,273 $ 53,892 ========= ========= The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements. 102
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2004 2003 ----------------------------- (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $3,660,955 $3,642,467 Less-Accumulated provision for depreciation.................................... 1,383,599 1,367,042 ---------- ---------- 2,277,356 2,275,425 Construction work in progress.................................................. 56,735 48,985 ---------- ---------- 2,334,091 2,324,410 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts........................................... 130,623 125,945 Nuclear fuel disposal trust.................................................... 159,710 155,774 Long-term notes receivable from associated companies........................... 20,635 19,579 Other.......................................................................... 18,085 18,744 ---------- ---------- 329,053 320,042 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 282 271 Receivables- Customers (less accumulated provisions of $3,924,000 and $4,296,000 respectively, for uncollectible accounts).................................. 182,797 198,061 Associated companies......................................................... 95,370 70,012 Other (less accumulated provisions of $836,000 and $1,183,000 respectively, for uncollectible accounts).................................. 34,879 46,411 Materials and supplies, at average cost........................................ 2,122 2,480 Prepayments and other.......................................................... 24,984 49,360 ---------- ---------- 340,434 366,595 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 2,456,605 2,558,214 Goodwill....................................................................... 1,998,287 2,001,302 Other.......................................................................... 8,547 8,481 ---------- ---------- 4,463,439 4,567,997 ---------- ---------- $7,467,017 $7,579,044 ========== ========== 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........................................................ 3,029,894 3,029,894 Accumulated other comprehensive loss......................................... (51,784) (51,765) Retained earnings............................................................ 30,406 22,132 ---------- ---------- Total common stockholder's equity........................................ 3,162,229 3,153,974 Preferred stock not subject to mandatory redemption............................ 12,649 12,649 Long-term debt................................................................. 1,041,032 1,095,991 ---------- ---------- 4,215,910 4,262,614 --------- ---------- CURRENT LIABILITIES: Currently payable long-term debt............................................... 226,313 175,921 Notes payable - Associated companies......................................................... 151,241 230,985 Accounts payable- Associated companies......................................................... 42,066 42,410 Other........................................................................ 90,810 105,815 Accrued taxes................................................................. 50,400 919 Accrued interest............................................................... 25,621 14,843 Other.......................................................................... 60,140 58,094 ---------- ---------- 646,591 628,987 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes.............................................. 623,875 640,208 Accumulated deferred investment tax credits.................................... 7,315 7,711 Power purchase contract loss liability ........................................ 1,416,257 1,473,070 Nuclear fuel disposal costs.................................................... 168,314 167,936 Asset retirement obligation.................................................... 111,379 109,851 Retirement benefits............................................................ 147,505 159,219 Other.......................................................................... 129,871 129,448 --------- ---------- 2,604,516 2,687,443 COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................ ---------- ---------- ---------- ---------- $7,467,017 $7,579,044 ========== ========== The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these balance sheets. 103
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, --------------------------- 2004 2003 --------- -------- Restated (See Note 2) (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................................... $ 13,398 $ 54,017 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........................... 94,701 96,973 Other amortization.................................................... 24 185 Deferred costs, net................................................... (49,122) (71,888) Deferred income taxes, net............................................ 627 14,977 Investment tax credits, net........................................... (397) (575) Receivables........................................................... 1,438 19,788 Materials and supplies................................................ 358 (226) Accounts payable...................................................... (15,349) (90,178) Prepayments and other current assets.................................. 24,376 16,044 Accrued taxes......................................................... 49,480 45,157 Accrued interest...................................................... 10,778 5,771 Accrued retirement benefit obligation................................. (11,714) -- Other................................................................. 3,444 6,034 --------- --------- Net cash provided from operating activities......................... 122,042 96,079 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Redemptions and Repayments - Long-term debt.......................................................... (3,591) (10,090) Short-term borrowings, net.............................................. (79,744) -- Dividend Payments- Common stock............................................................ (5,000) (89,000) Preferred stock......................................................... (125) (125) --------- --------- Net cash used for financing activities.............................. (88,460) (99,215) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................ (28,212) (24,551) Loans from (to) associated companies, net................................. (1,056) 24,750 Other..................................................................... (4,303) (50) --------- --------- Net cash provided from (used for) investing activities.............. (33,571) 149 --------- --------- Net increase (decrease) in cash and cash equivalents......................... 11 (2,987) Cash and cash equivalents at beginning of period ............................ 271 4,823 --------- --------- Cash and cash equivalents at end of period................................... $ 282 $ 1,836 ========= ========= The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements. 104
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, 2004, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2004 and 2003. 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 2 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the three-month period ended March 31, 2003. 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, 2003, 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 (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those consolidated financial statements) dated February 25, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, 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 7, 2004 105 JERSEY CENTRAL POWER & LIGHT COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L 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 PLR obligation known as BGS for customers who elect to retain JCP&L as their power supplier. Restatements of Previously Reported Quarterly Results ----------------------------------------------------- As discussed in Note 2 to Consolidated Financial Statements, JCP&L's quarterly results for the first quarter of 2003 have been restated to correct the amounts reported for operating expenses. JCP&L's costs which were originally recorded as operating expenses and should have been capitalized to construction were $0.2 million ($0.1 million after-tax) in the first quarter of 2003. The impact of these adjustments was not material to JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003. Results of Operation -------------------- Earnings on common stock in the first quarter of 2004 decreased to $13 million from $54 million in the first quarter of 2003. Lower operating revenues primarily due to decreases in wholesale sales and lower rates resulting from a NJBPU rate order and higher operating costs were partially offset by lower purchased power costs. Operating revenues decreased by $159 million or 24.2% in the first quarter of 2004 compared with the same period in 2003. The lower revenues resulted from lower wholesale revenues that decreased by $78 million over the first quarter of 2003. JCP&L entered into long-term power purchase agreements with the divestiture of its generating facilities. JCP&L was able to sell any power in excess of its retail customer needs to the wholesale market. The long-term power purchase agreements ended during 2003 and as a result, sales to the wholesale market also ceased. While distribution deliveries increased 1.3% in the first quarter of 2004 from the corresponding quarter of 2003, revenues from electricity throughput declined by $76 million. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision (see Regulatory Matters), which reduced JCP&L's distribution rates effective August 1, 2003. The lower rates reduced revenues by $33 million in the first quarter of 2004. A higher level of shopping contributed to the remainder of the decline in operating revenues. The industrial customer sector deliveries increased 6.1% primarily due to JCP&L's largest industrial customer increasing its consumption by 18%. Changes in distribution deliveries in the first quarter of 2004 compared with the first quarter of 2003 are summarized in the following table: Changes in Kilowatt-Hour Deliveries ---------------------------------------------------------- Increase (Decrease) Residential........................... 1.2% Commercial............................ (0.1)% Industrial............................ 6.1% ---------------------------------------------------------- Total Distribution Deliveries.................... 1.3% ========================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased $115 million in the first quarter of 2004 compared with the first quarter of 2003, primarily due to reduced purchased power costs offset in part by increased other operating expenses. The following table presents changes from the prior year by expense category. 106 Operating Expenses and Taxes - Changes ----------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................. $ -- Purchased power.................................. (103) Other operating costs............................ 17 ------------------------------------------------------------ Total operation and maintenance expenses....... (86) Provision for depreciation and amortization...... (2) General taxes.................................... -- Income taxes..................................... (27) ------------------------------------------------------------- Total operating expenses and taxes............. $(115) ============================================================= Lower purchased power costs in the first quarter of 2004, compared to the same quarter of 2003, were due primarily to decreased kilowatt-hour purchases through two-party agreements. The increase in other operating costs was attributed to JCP&L's accelerated reliability program (see Regulatory Matters). Net Interest Charges Net interest charges decreased by $2 million in the first quarter of 2004 compared with the first quarter of 2003, primarily due to debt redemptions since the end of the first quarter of 2003. Capital Resources and Liquidity ------------------------------- JCP&L's cash requirements in 2004 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 two 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 JCP&L had $0.3 million of cash and cash equivalents as of March 31, 2004 and December 31, 2003. Cash Flows From Operating Activities Cash provided from operating activities during the first quarter of 2004, compared to the first quarter of 2003 were as follows: Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 59 $94 Working capital and other............ 63 2 ------------------------------------------------------------- Total................................ $122 $96 ============================================================= (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 increased to $122 million in the first quarter of 2004 from $96 million in the first quarter of 2003. The increase was due to a $61 million increase in funds provided from working capital and other changes, partially offset by a $35 million decrease in cash earnings. The increase in working capital reflects a $75 million decrease in cash requirements for accounts payable in 2004 as compared to 2003. The cash earnings decrease was mostly attributable to lower revenues. Cash Flows From Financing Activities In the first quarter of 2004, net cash used for financing activities of $88 million primarily reflected the redemption of $80 million of short-term borrowings, $3 million of long-term debt and $5 million of common stock dividend payments to FirstEnergy. In the first quarter of 2003, net cash used for financing activities totaled $99 million, primarily due to the redemption of debt and $89 million in common stock dividend payments to FirstEnergy. JCP&L may borrow from its affiliates on a short-term basis. JCP&L will not issue first mortgage bonds other than as collateral for senior notes, since its senior note indenture prohibits (subject to certain exceptions) it from 107 issuing any debt which is senior to the senior notes. Based upon applicable earnings coverage tests, JCP&L could not issue any first mortgage bonds or preferred stock as of March 31, 2004. On April 23, 2004, JCP&L issued $300 million of 5.625% Senior Notes due 2016. The proceeds of this transaction will be used to redeem $40 million of 7.98% JCP&L Series C MTNs due 2023 and $50 million of 6.78% JCP&L Series C MTNs due 2005. The remaining proceeds will be used to fund the mandatory redemption of JCP&L's $160 million of 7.125% FMB due October 1, 2004 and to reduce short-term debt. JCP&L has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2004 was 1.30%. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy to restart the Davis-Besse nuclear plant was positive for credit quality because it would positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." Cash Flows From Investing Activities Net cash used for investing activities totaled $34 million in the first quarter of 2004, compared with net cash provided from investing activities of $0.1 million in the first quarter of 2003. The $34 million increase was primarily due to the $1 million in loan payments made to associated companies in 2004 as compared to the $25 million in loan payments received from associated companies in 2003, as well as $4 million in increased property additions in 2004. During the last three quarters of 2004, capital requirements for property additions are expected to be about $122 million. JCP&L has additional requirements of approximately $160 million for maturing long-term debt during the remainder of 2004. These cash requirements (excluding debt refinancings) are expected to be satisfied from internal cash and short-term credit arrangements. 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 2004 is summarized in the following table: 108 Increase (Decrease) in the Fair Value of Commodity Derivative Contracts
Non-Hedge Hedge Total ------------------------------------------------------------------------------------------------- (In millions) Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2004................... $ 16 $ -- $ 16 New contract value when entered............................... -- -- -- Additions/change in value of existing contracts............... (1) -- (1) Change in techniques/assumptions.............................. -- -- -- Settled contracts............................................. -- -- -- ------------------------------------------------------------------------------------------------- Net Assets - Derivatives Contracts as of March 31, 2004 (1)... $ 15 $ -- $ 15 ================================================================================================= Impact of Changes in Commodity Derivative Contracts (2) Income Statement Effects (Pre-Tax)............................ $ -- $ -- $ -- Balance Sheet Effects: Other Comprehensive Income (Pre-Tax).......................... $ -- $ -- $ -- Regulatory Liability.......................................... $ (1) $ -- $ (1)
(1) Includes $15 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. Derivatives included on the Consolidated Balance Sheet as of March 31, 2004: Non-Hedge Hedge Total --------------------------------------------------------------------- (In millions) Current- Other Assets...................... $-- $ -- $-- Non-Current- Other Deferred Charges............ 15 -- 15 ------------------------------------------------------------------- Net assets........................ $15 $ -- $15 =================================================================== 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:
Source of Information - Fair Value by Contract Year 2004 2005 2006 2007 Thereafter Total -------------------------------------------------------------------------------------------------------------- (In millions) Prices based on external sources(1) $ 2 $ 3 $ -- $ -- $ -- $ 5 Prices based on models -- -- 2 2 6 10 -------------------------------------------------------------------------------------------------------------- Total(2) $ 2 $ 3 $ 2 $ 2 $ 6 $15 ===============================================================================================================
(1) Broker quote sheets. (2) Includes $15 million from an embedded option that is offset by a regulatory liability and does not affect earnings. JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity 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, 2004. Equity Price Risk Included in JCP&L's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $72 million and $69 million as of March 31, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7 million reduction in fair value as of March 31, 2004. 109 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 FERC 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 $2.5 billion and $2.6 billion as of March 31, 2004 and December 31, 2003, 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's two August 2002 rate filings requested increases in base electric rates of approximately $98 million annually and requested the recovery of deferred energy 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. In July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision which reduced JCP&L's annual revenues by approximately $62 million effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base for the next six to twelve months. During that period, JCP&L will initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The revenue decrease in the decision consists of a $223 million decrease in the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC charge. The MTC allowed for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. As a result, JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million deferred energy costs and other regulatory assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on August 15, 2003 with respect to the following issues: (1) the disallowance of the $153 million deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7 million of disallowed costs to achieve merger savings. On October 10, 2003, the NJBPU held the motion in abeyance until the final NJBPU decision and order is issued. This is expected to occur in the second quarter of 2004. On July 5, 2003, JCP&L experienced a series of 34.5 kilo-volt sub-transmission line faults that resulted in outages on the New Jersey shore. The NJBPU instituted an investigation into these outages, and directed that a Special Reliability Master be hired to oversee the investigation. On December 8, 2003, the Special Reliability Master issued his Interim Report recommending that JCP&L implement a series of actions to improve reliability in the area affected by the outages. The NJBPU adopted the findings and recommendations of the Interim Report on December 17, 2003, and ordered JCP&L to implement the recommended actions on a staggered basis, with initial actions to be completed by March 31, 2004. JCP&L expects to spend $12.5 million implementing these actions during 2004. In late 2003, in accordance with a Stipulation concerning an August 2002 storm outage, the NJBPU engaged Booth & Associates to conduct an audit of the planning, operations and maintenance practices, policies and procedures of JCP&L. The audit was expanded to include the July 2003 outage and was completed in January 2004. JCP&L is awaiting the issuance of the final audit report and is unable to predict the outcome of the audit; no liability has been accrued as of March 31, 2004. On April 28, 2004, the NJBPU directed JCP&L to file testimony by the end of May 2004, either supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers, or, alternatively, proposing a reduction, termination or capping of the funding. JCP&L cannot predict the outcome of this matter. Environmental Matters JCP&L has been named as a 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, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, 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 by JCP&L through a non-bypassable SBC. JCP&L has accrued liabilities aggregating approximately $45.6 million as of March 31, 2004. JCP&L accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in JCP&L's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. 110 Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. -Canada Power System Outage Task Force released its final report on this outage. The final report supercedes the interim report that had been issued in November, 2003. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including, an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has undertaken several initiatives, some prior to and some since the August 14th power outage, to enhance reliability which are consistent with these and other recommendations and believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives below). As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. 111 With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against us, the most significant of which are described herein. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory. Since July 1999, this litigation has involved a substantial amount of legal discovery including interrogatories, request for production of documents, preservation and inspection of evidence, and depositions of the named plaintiffs and many JCP&L employees. In addition, there have been many motions filed and argued by the parties involving issues such as the primary jurisdiction and findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class decertification, and the damages claimed by the plaintiffs. In January 2000, the NJ Appellate Division determined that the trial court has proper jurisdiction over this litigation. In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict products liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings have been appealed to the Appellation Division and oral argument is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of March 31, 2004. Critical Accounting Policies JCP&L prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of JCP&L's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. JCP&L's more significant accounting policies are described below. Regulatory Accounting JCP&L is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine JCP&L is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in New Jersey, a significant amount of regulatory assets have been recorded - $2.5 billion as of March 31, 2004. JCP&L regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. JCP&L continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, JCP&L enters into commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments. 112 Revenue Recognition JCP&L follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 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. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% 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 144, JCP&L periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might 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 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). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. 113 Nuclear Decommissioning In accordance with SFAS 143, JCP&L recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of JCP&L's current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. JCP&L used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. 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, JCP&L evaluates 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), the goodwill is tested for impairment. If impairment were to be indicated, JCP&L would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. JCP&L's annual review was completed in the third quarter of 2003, with no impairment indicated. 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. In the first quarter of 2004, JCP&L reduced goodwill by $3 million for interest received on a pre-merger income tax refund. As of March 31, 2004, JCP&L had $2 billion of goodwill. New Accounting Standards and Interpretations FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, JCP&L adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on JCP&L's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. For the quarter ended March 31, 2004, JCP&L evaluated, among other entities, its power purchase agreements and determined that it is possible that six NUG entities might be considered variable interest entities. JCP&L has requested but not received the information necessary to determine whether these entities are VIEs or whether JCP&L is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. As such, JCP&L applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. JCP&L's purchased power costs from these entities during the first quarters of 2004 and 2003 were $28 million and $34 million, respectively. JCP&L is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. 114 METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31, ------------------------- 2004 2003 --------- -------- (In thousands) OPERATING REVENUES.............................................................. $ 260,898 $ 251,203 --------- --------- OPERATING EXPENSES AND TAXES: Purchased power.............................................................. 143,456 135,291 Other operating costs........................................................ 33,048 33,735 --------- --------- Total operation and maintenance expenses................................. 176,504 169,026 Provision for depreciation and amortization.................................. 35,395 34,108 General taxes................................................................ 17,736 16,860 Income taxes................................................................. 7,980 7,198 --------- --------- Total operating expenses and taxes....................................... 237,615 227,192 --------- --------- OPERATING INCOME................................................................ 23,283 24,011 OTHER INCOME.................................................................... 5,526 5,168 --------- --------- INCOME BEFORE NET INTEREST CHARGES.............................................. 28,809 29,179 --------- --------- NET INTEREST CHARGES: Interest on long-term debt................................................... 10,147 10,539 Allowance for borrowed funds used during construction........................ (71) (73) Deferred interest............................................................ -- (440) Other interest expense....................................................... 689 463 Subsidiary's preferred stock dividend requirements........................... -- 1,890 --------- --------- Net interest charges..................................................... 10,765 12,379 --------- --------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 18,044 16,800 Cumulative effect of accounting change (net of income taxes of $154,000) (Note 2) -- 217 --------- --------- NET INCOME...................................................................... $ 18,044 $ 17,017 ========= ========= The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements. 115
METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2004 2003 ------------------------------- (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $1,847,899 $1,838,567 Less-Accumulated provision for depreciation.................................... 780,873 772,123 ---------- ---------- 1,067,026 1,066,444 Construction work in progress.................................................. 20,599 21,980 ---------- ---------- 1,087,625 1,088,424 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts........................................... 200,502 192,409 Long-term notes receivable from associated companies........................... 10,636 9,892 Other.......................................................................... 33,814 34,922 ---------- ---------- 244,952 237,223 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 120 121 Receivables- Customers (less accumulated provisions of $4,886,000 and $4,943,000 respectively, for uncollectible accounts)................................. 114,964 118,933 Associated companies......................................................... 48,939 45,934 Notes receivable from associated companies................................... 126,525 10,467 Other (less accumulated provisions of $21,000 and $68,000 respectively, for uncollectible accounts)................................................ 17,947 22,750 Prepayments and other.......................................................... 43,201 6,600 ---------- ---------- 351,696 204,805 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 989,863 1,028,432 Goodwill....................................................................... 880,468 884,279 Other.......................................................................... 32,381 30,824 ---------- ---------- 1,902,712 1,943,535 ---------- ---------- $3,586,985 $3,473,987 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stockholder's equity - Common stock, without par value, authorized 900,000 shares- 859,500 shares outstanding................................................. $1,298,130 $1,298,130 Accumulated other comprehensive loss......................................... (35,721) (32,474) Retained earnings............................................................ 40,055 27,011 ---------- ---------- Total common stockholder's equity.......................................... 1,302,464 1,292,667 Long-term debt and other long-term obligations................................. 738,283 636,301 ---------- ---------- 2,040,747 1,928,968 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt............................................... 136,232 40,469 Short-term borrowings - Associated companies......................................................... - 65,335 Accounts payable- Associated companies......................................................... 64,378 45,459 Other........................................................................ 21,807 33,878 Accrued taxes................................................................. 7,216 8,762 Accrued interest............................................................... 7,383 11,848 Other.......................................................................... 23,242 22,162 ---------- ---------- 260,258 227,913 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes.............................................. 295,962 297,140 Accumulated deferred investment tax credits.................................... 11,491 11,696 Power purchase contract loss liability......................................... 551,598 584,340 Nuclear fuel disposal costs.................................................... 38,021 37,936 Asset retirement obligation.................................................... 213,261 210,178 Pensions and other postretirement benefits..................................... 106,625 105,552 Other.......................................................................... 69,022 70,264 ---------- ---------- 1,285,980 1,317,106 --------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................ ---------- ---------- $3,586,985 $3,473,987 ========== ========== The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets. 116
METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, --------------------------- 2004 2003 --------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................................... $ 18,044 $ 17,017 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........................... 35,395 34,108 Deferred costs, net................................................... (16,792) (10,767) Deferred income taxes, net............................................ 2,639 1,385 Amortization of investment tax credits................................ (206) (205) Accrued retirement benefit obligation................................. 1,074 -- Accrued compensation, net............................................. (634) (104) Cumulative effect of accounting change (Note 2)....................... -- (371) Receivables........................................................... 5,767 18,344 Materials and supplies................................................ 18 (139) Accounts payable...................................................... 6,848 31,968 Accrued taxes......................................................... (1,546) (11,916) Accrued interest...................................................... (4,465) (4,798) Prepayments and other current assets.................................. (36,618) (30,140) Other................................................................. (8,265) (11,613) --------- -------- Net cash provided from operating activities......................... 1,259 32,769 --------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt.......................................................... 247,607 247,696 Redemptions and Repayments- Long-term debt.......................................................... (50,435) (40,000) Short-term borrowings, net.............................................. (65,335) (23,087) Dividend Payments- Common Stock............................................................ (5,000) -- ---------- -------- Net cash provided from financing activities........................... 126,837 184,609 --------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................ (8,962) (10,333) Contributions to nuclear decommissioning trusts........................... (2,371) (2,371) Loans to associated companies, net........................................ (116,802) (8,005) Other..................................................................... 38 217 --------- -------- Net cash used for investing activities.............................. (128,097) (20,492) --------- -------- Net increase (decrease) in cash and cash equivalents......................... (1) 196,886 Cash and cash equivalents at beginning of period ............................ 121 15,685 --------- -------- --------- -------- Cash and cash equivalents at end of period................................... $ 120 $212,571 ========= ======== The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements. 117
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, 2004, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2004 and 2003. 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, 2003, 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 (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 8 to those consolidated financial statements) dated February 25, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, 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 7, 2004 118 METROPOLITAN EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed provides regulated transmission and distribution services in eastern 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 PLR obligations to customers who elect to retain Met-Ed as their power supplier. Results of Operations --------------------- Net income in the first quarter of 2004 increased to $18 million from $17 million in the first quarter of 2003. Results improved in the first quarter of 2004 due to increased retail electric sales revenues and lower interest charges, partially offset by higher purchased power costs. Operating revenues increased by $10 million, or 3.9% in the first quarter of 2004 compared with the first quarter of 2003. The higher revenues primarily resulted from increased distribution revenues of $10 million from electricity throughput as a result of higher unit prices and increased consumption by the commercial and industrial sectors -- reflecting the effects of an improving regional economy. Higher retail generation kilowatt-hour sales of 7.9% increased operating revenues by $2 million. The increase was primarily due to more commercial and industrial customers returning to Met-Ed as their electric service provider. Sales of electric generation by alternative suppliers as a percent of total sales delivered in Met-Ed's franchise area decreased to 10.3% in the first quarter of 2004 from 15.8% in the same period of 2003. Wholesale revenues decreased by $1 million, reflecting lower sales to affiliated companies and to the wholesale market. Changes in distribution deliveries in the first quarter of 2004 compared to the first quarter 2003 are summarized in the following table: Changes in Kilowatt-Hour Sales --------------------------------------------------- Increase (Decrease) Distribution Deliveries: Residential............................. (0.6)% Commercial.............................. 3.9% Industrial.............................. 1.5% --------------------------------------------------- Total Distribution Deliveries............. 1.3% =================================================== Operating Expenses and Taxes Total operating expenses and taxes increased $10 million in the first quarter of 2004 from the first quarter of 2003. Purchased power costs were $8 million higher due to increased PLR kilowatt-hour purchases from FES (due to increased generation sales requirements), partially offset by reduced above-market NUG costs. Other operating costs were lower in 2004 in part due to lower employee benefit costs. Depreciation and amortization expenses were higher due to increased amortization of regulatory assets related to CTC revenue recovery. General taxes increased due to gross receipts taxes and higher payroll taxes related to the transfer of employees to Met-Ed from GPUS. Net Interest Charges Net interest charges continued to trend lower, decreasing by $2 million in the first quarter of 2004 from the same quarter of last year, reflecting redemptions and refinancings since the end of 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 $217,000. The cumulative adjustment for unrecognized depreciation and accretion offset by the reduction in the existing decommissioning liabilities was a $371,000 increase to income, or $217,000 net of income taxes. 119 Capital Resources and Liquidity ------------------------------- Met-Ed expects to meet its cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and optional debt redemptions 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, 2004, Met-Ed had $120,000 of cash and cash equivalents compared with $121,000 as of December 31, 2003. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from operating activities in the first quarter of 2004 and 2003 were as follows: Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 39 $ 41 Working capital and other............ (38) (8) ------------------------------------------------------------- Total................................ $ 1 $ 33 ============================================================= (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 provided from operating activities decreased $32 million in the first quarter of 2004 from the first quarter of 2003 as a result of a $30 million decrease from working capital and other changes and a $2 million decrease in cash earnings. The largest factor contributing to the change in working capital was a $25 million decrease in accounts payable. Cash Flows From Financing Activities In the first quarter of 2004, net cash provided from financing activities of $127 million reflected the issuance of $250 million of senior notes, partially offset by the redemption of $50 million of long-term debt and $65 million of short-term debt, and a common stock dividend of $5 million to FirstEnergy. Net cash provided from financing activities totaled $185 million in the first quarter of 2003, due to 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. As of March 31, 2004, Met-Ed had approximately $127 million of cash and temporary investments (which include short-term notes receivable from associated companies) and no outstanding short-term borrowings. Met-Ed will not issue first mortgage bonds since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. Because Met-Ed satisfied the provisions of its senior note indenture for the release of all FMBs held as collateral for senior notes in March 2004, it is no longer required to issue FMBs as collateral for future issuances of senior notes and therefore not limited as to the amount of senior notes it may issue. Met-Ed had no restrictions on the issuance of preferred stock. Met-Ed has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Available bank borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2004 was 1.30%. In March 2004, Met-Ed completed an on-balance sheet, receivable financing transaction which allows it to borrow up to $80 million. The borrowing rate is based on bank commercial paper rates. Met-Ed is required to pay an annual facility fee of 0.30% on the entire finance limit. The facility was undrawn as of March 31, 2004. This facility matures on March 29, 2005. Met-Ed's access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. The ratings outlook on all of its securities is stable. 120 On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy to restart the Davis-Besse nuclear plant was positive for credit quality because it would positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." Cash Flows From Investing Activities In the first quarter of 2004, net cash used in investing activities totaled $128 million, compared to $20 million in the first quarter of 2003. The change resulted from a $108 million increase in loan payments to associated companies offset in part by slightly lower property additions. Expenditures for property additions primarily support Met-Ed's energy delivery operations. During the remaining quarters of 2004, capital requirements for property additions are expected to be about $46 million. Met-Ed has additional requirements of approximately $136 million for maturing long-term debt during the remainder of 2004. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Off-Balance Sheet Arrangements ------------------------------ As of March 31, 2004, off-balance sheet arrangements include certain statutory business trusts created by Met-Ed to issue trust preferred securities aggregating $93 million. These trusts were included in the consolidated financial statements of Met-Ed prior to the adoption of FIN 46R, but have subsequently been deconsolidated under FIN 46R (see Note 2 - Variable Interest Entities). Deconsolidation has not resulted in any change in outstanding debt. 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 2004 is summarized in the following table: 121 Increase (Decrease) in the Fair Value of Commodity Derivative Contracts
Non-Hedge Hedge Total -------------------------------------------------------------------------------------------------- (In millions) Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2004................... $ 31 $ -- $ 31 New contract value when entered............................... -- -- -- Additions/change in value of existing contracts............... (1) -- (1) Change in techniques/assumptions.............................. -- -- -- Settled contracts............................................. -- -- -- ------------------------------------------------------------------------------------------------- Net Assets - Derivatives Contracts as of March 31, 2004 (1)... $ 30 $ -- $ 30 ================================================================================================= Impact of Changes in Commodity Derivative Contracts (2) Income Statement Effects (Pre-Tax)............................ $ -- $ -- $ -- Balance Sheet Effects: Other Comprehensive Income (Pre-Tax).......................... $ -- $ -- $ -- Regulatory Liability.......................................... $ (1) $ -- $ (1)
(1) Includes $30 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. Derivatives included on the Consolidated Balance Sheet as of March 31, 2004: Non-Hedge Hedge Total ------------------------------------------------------------------- (In millions) Current- Other Assets...................... $-- $ -- $-- Non-Current- Other Deferred Charges............ 30 -- 30 ------------------------------------------------------------------- Net assets........................ $30 $ -- $30 =================================================================== 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:
Source of Information - Fair Value by Contract Year 2004 2005 2006 2007 Thereafter Total --------------------------------------------------------------------------------------------------------- (In millions) Prices based on external sources(1) $ 3 $ 5 $ -- $ -- $-- $ 8 Prices based on models -- -- 5 5 12 22 --------------------------------------------------------------------------------------------------------- Total(2) $ 3 $ 5 $ 5 $ 5 $12 $30 =========================================================================================================
(1) Broker quote sheets. (2) Includes $30 million from an embedded option that is offset by a regulatory liability and does not affect earnings. Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity 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, 2004. Equity Price Risk Included in Met-Ed's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $119 million and $114 million as of March 31, 2004 and December 31, 2003, 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, 2004. 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 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 122 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 FERC 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 its regulatory plan. Met-Ed's regulatory assets totaled $990 million and $1.03 billion as of March 31, 2004 and December 31, 2003, respectively. Regulatory Matters In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed to defer, for future recovery, energy costs in excess of amounts reflected in its capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. Met-Ed established a $103.0 million reserve in 2002 for its PLR deferred energy costs incurred prior to its acquisition by FirstEnergy, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. The reserve increased goodwill by an aggregate net of tax amount of $60.3 million. On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed Met-Ed to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Met-Ed's restructuring settlement previously approved by the PPUC. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The PPUC directed Met-Ed to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day's notice. In response to that order, Met-Ed filed these supplements to its tariffs to become effective October 24, 2003. On October 8, 2003, Met-Ed filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC's findings would not impair its rights to recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed for the NUG trust fund refund and, denying Met-Ed's other clarification requests and granting ARIPPA's petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Met-Ed to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 27, 2003, one Commonwealth Court judge issued an Order denying Met-Ed's objection without explanation. Due to the vagueness of the Order, Met-Ed, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed, in order to preserve its rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC's October 16 and October 22 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's objection was intended to be denied on the merits. In addition to these findings, Met-Ed, in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC's findings in their Orders. Effective September 1, 2002, Met-Ed agreed to purchase a portion of its PLR requirements from FES through a wholesale power sale agreement. The PLR sale 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 under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of Met-Ed'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 is authorized to continue deferring differences between NUG contract costs and current market prices. 123 In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. Met-Ed is currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Met-Ed's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year end of 2004. Met-Ed is unable to predict the outcome of the investigation or the impact of the PPUC order. Environmental Matters Met-Ed has been named as a 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, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, 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 $50,000 as of March 31, 2004. Met-Ed accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in Met-Ed's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. -Canada Power System Outage Task Force released its final report on this outage. The final report supercedes the interim report that had been issued in November, 2003. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including, an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has undertaken several initiatives, some prior to and some since the August 14th power outage, to enhance reliability which are consistent with these and other recommendations and believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives below). As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. 124 FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. 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. Critical Accounting Policies Met-Ed prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of Met-Ed's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Met-Ed's more significant accounting policies are described below. Regulatory Accounting Met-Ed is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Met-Ed is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded - $990 million as of March 31, 2004. Met-Ed regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. 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 125 documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. Met-Ed continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Met-Ed enters into commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments. Revenue Recognition Met-Ed follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 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. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% 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 144, Met-Ed periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might 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 has 126 occurred, Met-Ed recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, Met-Ed recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of Met-Ed's current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Met-Ed used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. 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, Met-Ed evaluates 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), the goodwill is tested for impairment. If impairment were to be indicated, Met-Ed would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. Met-Ed's annual review was completed in the third quarter of 2003, with no impairment indicated. 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 Met-Ed's future evaluations of goodwill. In the first quarter of 2004, Met-Ed reduced goodwill by $4 million for interest received on a pre-merger income tax refund. As of March 31, 2004, Met-Ed had $880 million of goodwill. New Accounting Standards and Interpretations -------------------------------------------- FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, Met-Ed adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on Met-Ed's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. For the quarter ended March 31, 2004, Met-Ed evaluated, among other entities, its power purchase agreements and determined that it is possible that one NUG entity might be considered a variable interest entity. Met-Ed has requested but not received the information necessary to determine whether this entity is a VIE or whether Met-Ed is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. As such, Met-Ed applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. Met-Ed's purchased power costs from this entity during the first quarters of 2004 and 2003 were $16 million and $15 million, respectively. Met-Ed is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. 127 PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31, --------------------------- 2004 2003 ---------- ---------- (In thousands) OPERATING REVENUES.............................................................. $ 256,445 $ 254,876 ---------- ---------- OPERATING EXPENSES AND TAXES: Purchased power.............................................................. 156,376 155,146 Other operating costs........................................................ 39,908 43,077 ---------- ---------- Total operation and maintenance expenses................................. 196,284 198,223 Provision for depreciation and amortization.................................. 25,089 25,337 General taxes................................................................ 16,962 15,744 Income taxes................................................................. 2,563 2,893 ---------- ---------- Total operating expenses and taxes....................................... 240,898 242,197 ---------- ---------- OPERATING INCOME................................................................ 15,547 12,679 OTHER EXPENSE................................................................... (84) (192) ----------- ---------- INCOME BEFORE NET INTEREST CHARGES.............................................. 15,463 12,487 ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt................................................... 7,447 7,339 Allowance for borrowed funds used during construction........................ (70) (81) Deferred interest............................................................ 190 (996) Other interest expense ...................................................... 2,237 143 Subsidiary's preferred stock dividend requirements........................... -- 1,888 ---------- ---------- Net interest charges..................................................... 9,804 8,293 ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 5,659 4,194 Cumulative effect of accounting change (net of income taxes of $777,000) (Note 2) -- 1,096 ---------- ---------- NET INCOME...................................................................... $ 5,659 $ 5,290 ========== ========== The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these statements. 128
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2004 2003 ------------------------------- (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $1,976,743 $1,966,624 Less-Accumulated provision for depreciation.................................... 796,606 785,715 ---------- ---------- 1,180,137 1,180,909 Construction work in progress.................................................. 29,374 29,063 ---------- ---------- 1,209,511 1,209,972 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Non-utility generation trusts.................................................. 94,660 43,864 Nuclear plant decommissioning trusts........................................... 105,615 102,673 Long-term notes receivable from associated companies........................... 13,865 13,794 Other.......................................................................... 19,117 19,635 ---------- ---------- 233,257 179,966 --------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 36 36 Receivables- Customers (less accumulated provisions of $5,872,000 and $5,833,000 respectively, for uncollectible accounts).................................. 117,489 124,462 Associated companies......................................................... 107,346 88,598 Other (less accumulated provisions of $388,000 and $399,000 respectively, for uncollectible accounts).................................. 16,121 15,767 Prepayments and other.......................................................... 49,564 2,511 ---------- ---------- 290,556 231,374 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 458,560 497,219 Goodwill....................................................................... 894,491 898,547 Accumulated deferred income tax benefits....................................... - 16,642 Other.......................................................................... 19,568 18,523 ---------- ---------- 1,372,619 1,430,931 ---------- ---------- $3,105,943 $3,052,243 ========== ========== 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........................................................ 1,215,667 1,215,667 Accumulated other comprehensive loss......................................... (42,180) (42,185) Retained earnings............................................................ 23,697 18,038 ---------- ---------- Total common stockholder's equity.......................................... 1,302,996 1,297,332 Long-term debt and other long-term obligations................................. 588,255 438,764 ---------- ---------- 1,891,251 1,736,096 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt .............................................. 125,605 125,762 Short-term borrowings- Associated companies......................................................... 17,185 78,510 Accounts payable- Associated companies......................................................... 56,391 55,831 Other........................................................................ 28,893 40,192 Accrued taxes................................................................. 2,222 8,705 Accrued interest............................................................... 15,330 12,694 Other.......................................................................... 25,068 21,764 ---------- ---------- 270,694 343,458 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes.............................................. 7,717 -- Accumulated deferred investment tax credits.................................... 9,691 9,936 Asset retirement obligation.................................................... 106,631 105,089 Nuclear fuel disposal costs.................................................... 19,010 18,968 Power purchase contract loss liability......................................... 629,965 670,482 Retirement benefits............................................................ 147,882 145,081 Other.......................................................................... 23,102 23,133 ---------- ---------- 943,998 972,689 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................ ---------- ---------- $3,105,943 $3,052,243 ========== ========== The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these balance sheets. 129
PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, --------------------------- 2004 2003 --------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income .................................................................. $ 5,659 $ 5,290 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........................... 25,089 25,337 Deferred costs recoverable as regulatory assets....................... (17,993) (11,656) Deferred income taxes, net............................................ 25,487 (41,640) Investment tax credits, net........................................... (245) (247) Accrued retirement benefit obligations................................ 2,802 -- Accrued compensation, net............................................. 2,255 62 Cumulative effect of accounting change (Note 2)....................... -- (1,873) Receivables........................................................... (12,129) 5,440 Accounts payable...................................................... (10,738) 8,666 Accrued taxes......................................................... (6,483) 27,284 Accrued interest...................................................... 2,636 5,679 Prepayments and other current assets.................................. (47,054) (34,778) Other................................................................. 3,654 (7,152) -------- -------- Net cash used for operating activities.............................. (27,060) (19,588) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt.......................................................... 150,000 -- Redemptions and Repayments- Long-term debt.......................................................... (104) -- Short-term borrowings, net.............................................. (61,326) (90,427) -------- --------- Net cash provided from (used for) financing activities.................... 88,570 (90,427) -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................ (11,194) (6,312) Non-utility generation trusts withdrawals (contributions)................. (50,614) 106,327 Loans to associated companies............................................. (71) -- Other, net................................................................ 369 -- -------- -------- Net cash provided from (used for) investing activities.............. (61,510) 100,015 --------- -------- Net change in cash and cash equivalents...................................... -- (10,000) Cash and cash equivalents at beginning of period ............................ 36 10,310 -------- -------- Cash and cash equivalents at end of period................................... $ 36 $ 310 ======== ======== The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these statements. 130
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, 2004, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2004 and 2003. 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, 2003, 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 (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 8 to those consolidated financial statements) dated February 25, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, 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 7, 2004 131 PENNSYLVANIA ELECTRIC COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Penelec is a wholly owned, electric utility subsidiary of FirstEnergy. Penelec provides regulated transmission and distribution services in western 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 PLR obligations to customers who elect to retain Penelec as their power supplier. Results from Operations ----------------------- Net income in the first quarter of 2004 increased to $5.7 million, compared to $5.3 million in the first quarter of 2003. 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 143. Income before the cumulative effect was $5.7 million in the first three months of 2004, compared to $4.2 million for the same period of 2003. The increase in net income was the result of higher operating revenues and lower operating costs -- partially offset by a lower level of deferred interest costs. Operating revenues increased by $1.6 million or 0.6% in the first quarter of 2004 compared with the same period in 2003. The higher revenues resulted from increased distribution revenues offset by lower retail generation revenues. Revenues from electricity throughput increased by $9 million as a result of higher unit prices which were partially offset by slightly lower distribution deliveries compared to the prior year. Penelec's retail generation kilowatt-hour sales increased 1.5% reflecting higher residential and commercial sales of 3.5% and 0.5%, respectively. Retail generation sales revenue decreased $5.3 million reflecting lower unit prices, which offset the generation sales increase as more customers returned from alternative suppliers. Although wholesale kilowatt-hour sales increased 121.3%, the volume was minimal for the first quarters of 2004 and 2003 and revenues increased only slightly. Changes in electric generation sales and distribution deliveries in the first quarter of 2004 from the first quarter of 2003 are summarized in the following table: Changes in Kilowatt-Hour Sales --------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ 1.5% Wholesale............................. 121.3% ------------------------------------------------- Total Electric Generation Sales......... 1.9% ================================================= Distribution Deliveries: Residential........................... 3.4% Commercial............................ 0.5% Industrial............................ (4.5)% -------------------------------------------------- Total Distribution Deliveries........... (0.4)% ================================================== 132 Operating Expenses and Taxes Total operating expenses and taxes decreased $1 million or 0.5% in the first quarter of 2004 from the first quarter of 2003, primarily due to lower other operating costs partially offset by increased purchased power costs and general taxes. The following table presents changes during the first quarter of 2004 from the same period in 2003 for operating expenses and taxes. Operating Expenses and Taxes - Changes ----------------------------------------------------------------- Increase (Decrease) (In millions) Purchased power ................................. $ 1 Other operating costs............................ (3) ----------------------------------------------------------------- Total operation and maintenance expenses....... (2) Provision for depreciation and amortization...... -- General taxes.................................... 1 Income taxes..................................... -- ----------------------------------------------------------------- Total operating expenses and taxes............. $ (1) ================================================================= Lower other operating costs in the first quarter of 2004, compared with the same quarter of 2003, were due to reduced postretirement benefit plan expenses, lower uncollectible customer accounts and transmission expenses. Purchased power costs increased due primarily to increased PLR purchases from FES, partially offset by reduced two-party energy purchases. General taxes increased due to higher payroll taxes from the transfer of employees to Penelec from GPUS. Net Interest Charges Net interest charges increased by $1.5 million in the first quarter of 2004 compared with the first quarter of 2003, reflecting a lower level of deferred interest costs. 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. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice depreciating non-regulated generation assets using a cost of removal component was an $1.9 million increase to income, or $1.1 million net of income taxes. Capital Resources and Liquidity ------------------------------- Penelec's cash requirements in 2004 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 two 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, 2004 and December 31, 2003, Penelec had $36,000 of cash and cash equivalents. Cash Flows From Operating Activities Cash used by operating activities in the first quarter of 2004, compared with the first quarter of 2003 were as follows: Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 43 $ (25) Working capital and other............ (70) 5 ------------------------------------------------------------- Total................................ $(27) $ (20) ============================================================= (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and pension changes. Net cash used for operating activities increased to $27 million in the first quarter of 2004 from $20 million in the same period of 2003. In 2004, the increase was due to the increase of working capital requirements (primarily from changes in accounts receivable and payable) offset by an increase in cash earnings from higher deferred income taxes. Cash Flows From Financing Activities Net cash provided from financing activities of $89 million in the first quarter of 2004 compared to net cash used for financing activities of $90 million in the first quarter of 2003, represents the issuance in March 2004 of $150 million of long-term debt partially offset by a decrease in short-term borrowings. The proceeds from the $150 million issuance were used to redeem $125 133 million principal amount of senior notes that matured on April 1, 2004 and to repay short-term borrowings. As of March 31, 2004, Penelec had $17 million of short-term indebtedness, compared to $79 million at the end of 2003. Penelec may borrow from its affiliates on a short-term basis. Penelec will not issue first mortgage bonds other than as collateral for senior notes, since its senior note indenture prohibits (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of March 31, 2004, Penelec had the capability to issue $6.5 million of additional senior notes based upon first mortgage bond collateral. Penelec had no restrictions on the issuance of preferred stock. In March 2004, Penelec completed an on-balance sheet, receivable financing transaction which allows it to borrow up to $75 million. The borrowing rate is based on bank commercial paper rates. Penelec is required to pay an annual facility fee of 0.30% on the entire finance limit. The facility was undrawn as of March 31, 2004. This facility matures on March 29, 2005. Penelec's access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook on all of its securities is stable. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy to restart the Davis-Besse nuclear plant was positive for credit quality because it would positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." Cash Flows From Investing Activities Net cash used for investing activities were $62 million in the first quarter of 2004, compared to net cash provided from investing activities totaling $100 million in the first quarter of 2003. The net cash used for investing activities resulted from a refunding payment of $51 million to a NUG trust fund and increased property additions in 2004. In the first quarter of 2003, net cash provided from investing activities resulted from $106 million of withdrawals from the NUG trust fund, partially offset by property additions. Expenditures for property additions primarily support Penelec's energy delivery operations. During the remaining quarters of 2004, capital requirements for property additions are expected to be about $54 million. Penelec has additional requirements of approximately $125 million for maturing long-term debt during the remainder of 2004. These cash requirements (excluding debt refinancings) are expected to be satisfied from internal cash and short-term credit arrangements. Off-Balance Sheet Arrangements ------------------------------ As of March 31, 2004, Penelec's off-balance sheet arrangements included certain statutory business trusts created by Penelec to issue trust preferred securities of $92 million. These trusts were included in Penelec's financial statements prior to the adoption of FIN 46R, but have subsequently been deconsolidated under FIN 46R (see Note 2 - Variable Interest Entities). This deconsolidation has not resulted in any change in outstanding debt. 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 independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. 134 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 2004 is summarized in the following table: Increase (Decrease) in the Fair Value of Commodity Derivative Contracts
Non-Hedge Hedge Total ----------------------------------------------------------------------------------------------- (In millions) Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2004................... $15 $ -- $15 New contract value when entered............................... -- -- -- Additions/change in value of existing contracts............... -- -- -- Change in techniques/assumptions.............................. -- -- -- Settled contracts............................................. -- -- -- ----------------------------------------------------------------------------------------------- Net Assets - Derivatives Contracts as of March 31, 2004 (1)... $15 $ -- $15 ===============================================================================================
(1) Includes $14 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. Derivatives included on the Consolidated Balance Sheet as of March 31, 2004: Non-Hedge Hedge Total --------------------------------------------------------------------- (In millions) Current- Other Assets...................... $-- $ -- $-- Non-Current- Other Deferred Charges............ 15 -- 15 --------------------------------------------------------------------- Net assets........................ $15 $ -- $15 ===================================================================== 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:
Source of Information - Fair Value by Contract Year 2004 2005 2006 2007 Thereafter Total ------------------------------------------------------------------------------------------------- (In millions) Prices based on external sources(1)... $ 2 $ 3 $-- $ -- $-- $ 5 Prices based on model................. -- -- 2 2 6 10 ------------------------------------------------------------------------------------------------- Total(2).......................... $ 2 $ 3 $ 2 $ 2 $ 6 $15 =================================================================================================
(1) Broker quote sheets. (2) Includes $14 million from an embedded option that is offset by a regulatory liability and does not affect earnings. Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity 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, 2004. Equity Price Risk Included in Penelec's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $55 million and $54 million as of March 31, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of March 31, 2004. 135 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 PPUC authorized Penelec'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. 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 FERC 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 $459 million and $497 million as of March 31, 2004 and December 31, 2003, respectively. Regulatory Matters In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Penelec to defer, for future recovery, energy costs in excess of amounts reflected in its capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. Penelec established a $111.1 million reserve in 2002 for its PLR deferred energy costs incurred prior to its acquisition by FirstEnergy, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. The reserve increased goodwill by an aggregate net of tax amount of $65.0 million. On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Penelec filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Penelec's restructuring settlement previously approved by the PPUC. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The PPUC directed Penelec to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day's notice. In response to that order, Penelec filed these supplements to its tariffs to become effective October 24, 2003. On October 8, 2003, Penelec filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC's findings would not impair its rights to recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Penelec for the NUG trust fund refund and, denying Penelec's other clarification requests and granting ARIPPA's petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 27, 2003, one Commonwealth Court judge issued an Order denying Penelec's objection without explanation. Due to the vagueness of the Order, Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Penelec, in order to preserve its rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC's October 16 and October 22 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Penelec's objection was intended to be denied on the merits. In addition to these findings, Penelec, in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC's findings in their Orders. 136 Effective September 1, 2002, Penelec agreed to purchase a portion of its PLR requirements from FES through a wholesale power sale agreement. The PLR sale 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 Penelec under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Penelec's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of 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. Penelec is authorized to continue deferring differences between NUG contract costs and current market prices. In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. Penelec is currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. On January 16, 2004, the PPUC initiated a formal investigation of whether Penelec's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Penelec's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year end of 2004. Penelec is unable to predict the outcome of the investigation or the impact of the PPUC order. Environmental Matters Penelec has been named as a 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, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, 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 accrued liabilities aggregating approximately $30,000 as of March 31, 2004. Penelec accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in Penelec's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. -Canada Power System Outage Task Force released its final report on this outage. The final report supercedes the interim report that had been issued in November, 2003. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including, an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy's website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has undertaken several initiatives, some prior to and some since the August 14th power outage, to enhance reliability which are consistent with these and other recommendations and believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives below). As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. 137 FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. 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. Critical Accounting Policies Penelec prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of Penelec's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Penelec's more significant accounting policies are described below. Regulatory Accounting Penelec is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Penelec is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded - $459 million as of March 31, 2004. Penelec regularly reviews these assets to assess their ultimate 138 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 its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Penelec enters into commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments. Revenue Recognition Penelec follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided 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 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 in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also 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 and SFAS 106, 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 recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 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. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. 139 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 144, Penelec periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might 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 has occurred, Penelec recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, Penelec recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of Penelec's current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Penelec used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7 to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. 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, Penelec evaluates 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), the goodwill is tested for impairment. If impairment were to be indicated Penelec would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. Penelec's annual review was completed in the third quarter of 2003, with no impairment indicated. The forecasts used in Penelec's 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. In the first quarter of 2004, Penelec reduced goodwill by $4 million for interest received on a pre-merger income tax refund. As of March 31, 2004, Penelec had $894 million of goodwill. New Accounting Standards and Interpretations FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, Penelec adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on Penelec's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. 140 For the quarter ended March 31, 2004, Penelec evaluated, among other entities, its power purchase agreements and determined that it is possible that two NUG entities might be considered variable interest entities. Penelec has requested but not received the information necessary to determine whether these entities are VIEs or whether Penelec is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. As such, Penelec applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. The cost of purchased power from these entities was $7 million in each of the quarters ended March 31, 2004 and 2003. Penelec is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. 141 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ------------------------------------------------------------------- See "Management's Discussion and Analysis of Results of Operation and Financial Condition - Market Risk Information" in Item 2 above. ITEM 4. CONTROLS AND PROCEDURES -------------------------------- (a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES The applicable registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end of the date covered by this report. 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 material information relating to the registrant and its consolidated subsidiaries by others within those entities. (b) CHANGES IN INTERNAL CONTROLS During the quarter ended March 31, 2004, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting. 142 PART II. OTHER INFORMATION --------------------------- Item 1. Legal Proceedings ----------------- Reference is made to Note 3, Commitments, Guarantees and Contingencies, of the Notes to Consolidated Financial Statements contained in Part I, Item 1 for a description of certain legal proceedings. Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits Exhibit Number ------ Met-Ed ------ 12 Fixed charge ratios 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. Penelec ------- 12 Fixed charge ratios 15 Letter from independent accountants 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chie financial officer, pursuant to 18 U.S.C. Section 1350. JCP&L ----- 12 Fixed charge ratios 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.3 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.2 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. FirstEnergy ----------- 10-40 Employment, severance and change in control agreement between FirstEnergy Corp. and A. J. Alexander, dated February 17, 2004. 15 Letter from independent accountants 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. OE and Penn ----------- 15 Letter from independent accountants 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. CEI and TE ---------- 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. 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. 143 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, CEI and TE ----------------------- FirstEnergy, CEI and TE each filed the following four reports on Form 8-K since December 31, 2003: A report dated January 13, 2004 reported FirstEnergy Chief Executive Officer H. Peter Burg passed away. A report dated January 20, 2004 reported Anthony J. Alexander elected as FirstEnergy Chief Executive Officer and George M. Smart elected as FirstEnergy Chairman of the Board of Directors. A report dated February 9, 2004 reported Moody's lowered debt ratings for FirstEnergy and subsidiaries. A report dated March 8, 2004 reported that FirstEnergy began Davis-Besse restart with NRC authorization. OE, Penn, JCP&L, Met-Ed and Penelec ----------------------------------- OE, Penn, JCP&L, Met-Ed and Penelec each filed the following three reports on Form 8-K since December 31, 2003: A report dated January 13, 2004 reported FirstEnergy Chief Executive Officer H. Peter Burg passed away. A report dated January 20, 2004 reported Anthony J. Alexander elected as FirstEnergy Chief Executive Officer and George M. Smart elected as FirstEnergy Chairman of the Board of Directors. A report dated February 9, 2004 reported Moody's lowered debt ratings for FirstEnergy and subsidiaries. 144 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 10, 2004 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 145