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 September 30, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ----------------- ------------------- Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. - ----------- ----------------------------------------- ------------------ 333-21011 FIRSTENERGY CORP. 34-1843785 (An Ohio Corporation) 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-2578 OHIO EDISON COMPANY 34-0437786 (An Ohio Corporation) 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 34-0150020 (An Ohio Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3583 THE TOLEDO EDISON COMPANY 34-4375005 (An Ohio Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3491 PENNSYLVANIA POWER COMPANY 25-0718810 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3141 JERSEY CENTRAL POWER & LIGHT COMPANY 21-0485010 (A New Jersey Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-446 METROPOLITAN EDISON COMPANY 23-0870160 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3522 PENNSYLVANIA ELECTRIC COMPANY 25-0718085 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402
Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ---- ----- Indicate by check mark whether each registrant is an accelerated filer ( as defined in Rule 12b-2 of the Act): Yes X No ---- ----- Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: OUTSTANDING CLASS AS OF NOVEMBER 13, 2003 ----- ----------------------- 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), availability and cost of capital, inability of the Davis-Besse Nuclear Power Station to restart (including because of an inability to obtain a favorable final determination from the Nuclear Regulatory Commission) in the fall of 2003, inability to accomplish or realize anticipated benefits from strategic goals, the ability to access the public securities markets, further investigation into the causes of the August 14, 2003 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 the Company's Application related to its Rate Stabilization Plan, and other factors discussed from time to time in FirstEnergy's Securities and Exchange Commission filings, including its annual report on Form 10-K (as amended) for the year ended December 31, 2002, and under "Risk Factors" in the Prospectus Supplement dated September 12, 2003 to the Prospectus dated August 29, 2003 (which was part of the Registration Statement-File No. 333-103865) and other similar factors.
TABLE OF CONTENTS Pages Part I. Financial Information Notes to Financial Statements................................... 1-22 FirstEnergy Corp. Consolidated Statements of Income............................... 23 Consolidated Balance Sheets..................................... 24-25 Consolidated Statements of Cash Flows........................... 26 Report of Independent Accountants............................... 27 Management's Discussion and Analysis of Results of Operations and Financial Condition............................ 28-51 Ohio Edison Company Consolidated Statements of Income............................... 52 Consolidated Balance Sheets..................................... 53-54 Consolidated Statements of Cash Flows........................... 55 Report of Independent Accountants............................... 56 Management's Discussion and Analysis of Results of Operations and Financial Condition............................ 57-65 The Cleveland Electric Illuminating Company Consolidated Statements of Income............................... 66 Consolidated Balance Sheets..................................... 67-68 Consolidated Statements of Cash Flows........................... 69 Report of Independent Accountants............................... 70 Management's Discussion and Analysis of Results of Operations and Financial Condition............................ 71-80 The Toledo Edison Company Consolidated Statements of Income............................... 81 Consolidated Balance Sheets..................................... 82-83 Consolidated Statements of Cash Flows........................... 84 Report of Independent Accountants............................... 85 Management's Discussion and Analysis of Results of Operations and Financial Condition............................ 86-94 Pennsylvania Power Company Statements of Income............................................ 95 Balance Sheets.................................................. 96-97 Statements of Cash Flows........................................ 98 Report of Independent Accountants............................... 99 Management's Discussion and Analysis of Results of Operations and Financial Condition............................ 100-106 Jersey Central Power & Light Company Consolidated Statements of Income............................... 107 Consolidated Balance Sheets..................................... 108-109 Consolidated Statements of Cash Flows........................... 110 Report of Independent Accountants............................... 111 Management's Discussion and Analysis of Results of Operations and Financial Condition............................ 112-120
TABLE OF CONTENTS (Cont'd) Pages Metropolitan Edison Company Consolidated Statements of Income............................... 121 Consolidated Balance Sheets..................................... 122-123 Consolidated Statements of Cash Flows........................... 124 Report of Independent Accountants............................... 125 Management's Discussion and Analysis of Results of Operations and Financial Condition............................ 126-134 Pennsylvania Electric Company Consolidated Statements of Income............................... 135 Consolidated Balance Sheets..................................... 136-137 Consolidated Statements of Cash Flows........................... 138 Report of Independent Accountants............................... 139 Management's Discussion and Analysis of Results of Operations and Financial Condition............................ 140-148 Quantitative and Qualitative Disclosures About Market Risk........... 149 Controls and Procedures.............................................. 149 Part II. Other Information
PART I. FINANCIAL INFORMATION - ----------------------------- FIRSTENERGY CORP. AND SUBSIDIARIES OHIO EDISON COMPANY AND SUBSIDIARIES THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES THE TOLEDO EDISON COMPANY AND SUBSIDIARY PENNSYLVANIA POWER COMPANY JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES METROPOLITAN EDISON COMPANY AND SUBSIDIARIES PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (UNAUDITED) 1 - FINANCIAL STATEMENTS: The principal business of FirstEnergy Corp. (FirstEnergy) is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE), Pennsylvania Power Company (Penn), American Transmission Systems, Inc. (ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). These utility subsidiaries are referred to throughout as "Companies." Penn is a wholly owned subsidiary of OE. JCP&L, Met-Ed and Penelec were acquired in a merger (which was effective November 7, 2001) with GPU, Inc., the former parent company of JCP&L, Met-Ed and Penelec. The merger was accounted for by the purchase method of accounting and the applicable effects were reflected on the financial statements of JCP&L, Met-Ed and Penelec as of the merger date. FirstEnergy's consolidated financial statements also include its other principal subsidiaries: FirstEnergy Solutions Corp. (FES); FirstEnergy Facilities Services Group, LLC (FSG); MYR Group, Inc.; MARBEL Energy Corporation; FirstEnergy Nuclear Operating Company (FENOC); GPU Capital, Inc.; GPU Power, Inc.; and FirstEnergy Service Company (FESC). FES provides energy-related products and services and, through its FirstEnergy Generation Corp. (FGCO) subsidiary, operates FirstEnergy's nonnuclear generation business. FENOC operates the Companies' nuclear generating facilities. FSG is the parent company of several heating, ventilating, air conditioning and energy management companies, and MYR is a utility infrastructure construction service company. MARBEL holds FirstEnergy's interest in Great Lakes Energy Partners, LLC. GPU Capital owns and operates electric distribution systems in foreign countries (see Note 3) and GPU Power owns and operates generation facilities in foreign countries. FESC provides legal, financial and other corporate support services to affiliated FirstEnergy companies. Significant intercompany transactions have been eliminated. The Companies follow the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC), the New Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC). The condensed unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K, as amended where applicable, for the year ended December 31, 2002 for FirstEnergy and the Companies. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (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. Certain prior year amounts have been reclassified to conform with the current year presentation, as discussed further in Note 5, and restated as discussed below. 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. Preferred Securities The sole assets of the CEI subsidiary trust that is the obligor on the preferred securities included in FirstEnergy's and CEI's Capitalizations are $103.1 million aggregate principal amount of 9% junior subordinated debentures of CEI due December 31, 2006. CEI has effectively provided a full and unconditional guarantee of the trust's obligations under the preferred securities. 1
Met-Ed and Penelec each formed statutory business trusts for the issuance of $100 million each of preferred securities due 2039 and are included in FirstEnergy's, Met-Ed's and Penelec's respective capitalizations. Ownership of the respective Met-Ed and Penelec trusts is through separate wholly owned limited partnerships, of which a wholly owned subsidiary of each company is the sole general partner. In these transactions, the sole assets and sources of revenues of each trust are the preferred securities of the applicable limited partnership, whose sole assets are the 7.35% and 7.34% subordinated debentures (aggregate principal amount of $103.1 million each) of Met-Ed and Penelec, respectively. In each case, the applicable parent company has effectively provided a full and unconditional guarantee of the trust's obligations under the preferred securities. The continued consolidation of the issuer trusts and the appropriate balance sheet classification of trust preferred securities is currently under review pursuant to FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51." Upon the implementation of FIN 46 effective December 31, 2003, these trusts would be deconsolidated if CEI, Met-Ed and Penelec were not the primary beneficiaries of the related trusts. Such a deconsolidation would result in FirstEnergy, CEI, Met-Ed and Penelec reflecting liabilities for the subordinated notes payable to the respective trusts, which are currently eliminated in consolidation. We currently classify the trust preferred securities as long-term debt in our consolidated balance sheets. The deconsolidation of the issuer trusts would result in an increase to total assets and liabilities of $9.3 million ($3.1 million for each of CEI, Met-Ed and Penelec) for the investment in the trusts. Securitized Transition Bonds In June 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of JCP&L, sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. JCP&L 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 the Issuer and are collateralized solely by the equity and assets of the Issuer, which consist primarily of bondable transition property. The bondable transition property is solely the property of the Issuer. Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable transition bond charge, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L sold the bondable transition property to the Issuer and as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the transition bond charge, pursuant to a servicing agreement with the Issuer. JCP&L is entitled to a quarterly servicing fee of $100,000 that is payable from transition bond charge collections. Pension and Other Postretirement Benefits As a result of GPU Service Inc. merging with FESC in the second quarter of 2003, operating company employees of GPU Service were transferred to JCP&L, Met-Ed and Penelec. Due to the significance of the transfers, FirstEnergy engaged its actuary to evaluate how to allocate the pension and other post-employment benefit (OPEB) assets and liabilities for each of its subsidiaries. Based on the actuary's report, the accrued pension and OPEB costs for FirstEnergy and its subsidiaries as of June 30, 2003 increased (decreased) by the following amounts: Pension OPEB ------- ---- (In thousands) OE............................. $ 50,937 $ 48,775 CEI............................ (16,699) (49,526) TE............................. (3,439) (24,476) Penn........................... 15,851 9,751 JCP&L.......................... 78,549 86,333 Met-Ed......................... 47,219 59,405 Penelec........................ 70,693 87,314 Other subsidiaries............. (243,111) (217,576) --------- --------- Total FirstEnergy.............. $ -- $ -- ========= ========= The corresponding adjustment related to these changes increased (decreased) other comprehensive income, deferred income taxes and receivables from/to associated companies in the respective operating company's financial statements. 2
Derivative Accounting FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including electricity, natural gas and coal. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. FirstEnergy uses derivatives to hedge the risk of price and interest rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The maximum periods over which the variability of electricity and natural gas cash flows are hedged are two and three years, respectively. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. Also, gains and losses are included in net income when ineffectiveness occurs on certain natural gas hedges. FirstEnergy entered into interest rate derivative transactions during 2001 to hedge a portion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from hedges of anticipated interest payments on acquisition debt 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 of $115.1 million included in Accumulated Other Comprehensive Loss (AOCL) as of September 30, 2003, for derivative hedging activity, as compared to the June 30, 2003 balance of $110.8 million in net deferred losses, resulted from an $8.2 million reduction related to current hedging activity and a $12.5 million increase due to net hedge gains included in earnings during the three months ended September 30, 2003. Approximately $22.1 million (after tax) of the net deferred loss on derivative instruments in AOCL as of September 30, 2003, 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. FirstEnergy periodically enters into fixed-to-floating interest rate swap agreements to increase the variable-rate component of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options and interest payment dates match those of the underlying obligations resulting in no ineffectiveness in these hedge positions. The swap agreement consummated in the third quarter of 2003 is based on a notional principal amount of $50 million. As of September 30, 2003, the notional amount of FirstEnergy's fixed-for-floating rate interest rate swaps totaled $600 million. 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 Statement of Financial Accounting Standards (SFAS) 142, FirstEnergy evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. When 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. 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 $121.5 million was recognized in the third quarter of 2003, reducing the carrying value of FSG. That charge reflects the continued slow down in the development of competitive retail markets and depressed economic conditions that affect the value of FSG. The fair value of FSG was estimated using primarily the expected discounted future cash flows.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 September 30, 2003, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. A summary of the changes in FirstEnergy's goodwill for the nine months ended September 30, 2003 (which affected only the Competitive Services Segment) is shown below: In millions) Balance at December 31, 2003............ $6,278.1 Impairment charges...................... (121.5) FSG divestitures........................ (40.8) Other................................... 12.1 -------- Balance at September 30, 2003........... $6,127.9 ======== 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 3
of September 30, 2003, FirstEnergy's AOCL was approximately $532.6 million as compared to the December 31, 2002 balance of $656.1 million. A reconciliation of net income to comprehensive income for the three months and nine months ended September 30, 2003 and 2002, is shown below: <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, ------------------------ --------------------- 2003 2002 2003 2002 ---- ---- ---- ---- Restated Restated (see Note 1) (see Note 1) (In thousands) (In thousands) <S> <C> <C> <C> <C> Net income............................. $152,719 $284,845 $313,333 $611,011 Other comprehensive income, net of tax: Derivative hedge transactions........ (4,346) 16,373 (4,922) 52,752 Currency translations (1)............ (11) -- 91,450 1 Available for sale securities........ 5,880 (1,068) 44,148 (2,479) -------- -------- -------- -------- Comprehensive income................... $154,242 $300,150 $444,009 $661,285 ======== ======== ======== ======== <FN> (1) See Note 3 - International Operations (Emdersa Abandonment). </FN> </TABLE> Stock-Based Compensation FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans. No material stock-based employee compensation expense is reflected in net income as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method, a higher value would have been assigned to the options granted. The effects of applying fair value accounting to FirstEnergy's stock options would be reductions to net income and earnings per share. The following table summarizes those effects. <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, ----------------------- --------------------- 2003 2002 2003 2002 ---- ---- ---- ---- Restated Restated (see Note 1) (see Note 1) (In thousands) (In thousands) <S> <C> <C> <C> <C> Net income, as reported................... $152,719 $284,845 $313,333 $611,011 Add back compensation expense reported in net income, net of tax (based on APB 25)....................... 40 39 131 126 Deduct compensation expense based upon estimated fair value, net of tax... (3,138) (2,491) (9,314) (6,432) -------------------------------------------------------------------------------------------------- Adjusted net income....................... $149,621 $282,393 $304,150 $604,705 -------------------------------------------------------------------------------------------------- Earnings Per Share of Common Stock - Basic As Reported.......................... $0.51 $0.97 $1.06 $2.08 Adjusted............................. $0.50 $0.96 $1.03 $2.06 Diluted As Reported.......................... $0.51 $0.97 $1.05 $2.08 Adjusted............................. $0.50 $0.96 $1.02 $2.05 </TABLE> Changes in Previously Reported Income Statement Classifications FirstEnergy recorded an increase to income during the first quarter of 2002 of $31.7 million (net of income taxes of $13.6 million) relative to a decision to retain an interest in the Avon Energy Partners Holdings (Avon) business previously classified as held for sale - see Note 3. This amount represents the aggregate results of operations of Avon for the period this business was held for sale. It was previously reported on the Consolidated Statement of Income as the cumulative effect of a change in accounting. In April 2003, it was determined that this amount should instead have been classified in operations. As further discussed in Note 3, the decision to retain Avon was made in the first quarter of 2002 and Avon's results of operations for that quarter have been classified in their respective revenue and expense captions 4
on the Consolidated Statement of Income. This change in classification had no effect on previously reported net income. The effects of this change on the Consolidated Statement of Income previously reported for the nine months ended September 30, 2002 are reflected in the restatements shown below. As a result of FirstEnergy's divestiture of its ownership in GPU Empresa Distribuidora Electrica Regional S.A. and affiliates (Emdersa) in April 2003 through the abandonment of its shares in the parent company of the Argentina operation (as further described in Note 3), FirstEnergy recorded a $67.4 million charge in the second quarter of 2003 on the Consolidated Statement of Income as "Discontinued Operations". This divestiture caused Emdersa's first quarter 2003 net income of approximately $6.9 million, which had been previously classified in its respective revenues and expense captions on the Consolidated Statement of Income, to be also reclassified as Discontinued Operations. Accordingly, Emdersa's Discontinued Operations reflect a $60.5 million net loss for the nine months ended September 30, 2003 which included $6.9 million of after-tax earnings from the Argentina operation from the first quarter of 2003 - previously reported as $10.7 million of revenue, $0.1 million of expenses and $3.7 million of income taxes. The following table summarizes Emdersa's major assets and liabilities included in FirstEnergy's Consolidated Balance Sheet as of December 31, 2002: (In thousands) ------------------------------------------------- Assets Abandoned: Current Assets..................... $ 17,344 Property, plant and equipment...... 61,980 Other.............................. 8,737 ------------------------------------------------ Total Assets......................... $ 88,061 ================================================ Liabilities Related to Assets Abandoned: Current Liabilities................ $ 12,777 Long-term debt..................... 100,202 Other.............................. 10,548 ------------------------------------------------ Total Liabilities.................... $123,527 ================================================ RESTATEMENTS OF PREVIOUSLY REPORTED RESULTS FirstEnergy, OE, CEI and TE have restated their financial statements for the year ended December 31, 2002, for the three months ended March 31, 2003 and 2002, the six months ended June 30, 2003, the three and six months ended June 30, 2002 and the three and nine months ended September 30, 2002. The primary modifications include revisions to reflect a change in the method of amortizing costs being recovered through the Ohio transition plan and recognition of above-market values of certain leased generation facilities. In addition, certain other immaterial adjustments recorded in the first quarter of 2003 that related to 2002 are now reported in results for the earlier periods. The net impact of these adjustments decreased net income by $6.2 million in the first quarter of 2003. Included in the adjustments are the impact in the first and second quarters of 2002 of ceasing deferral accounting for certain energy costs incurred in Pennsylvania (see Note 4). The impact of this restatement increased net income in the first quarter of 2002 by $12 million and decreased net income in the second quarter of 2002 by $8 million. Transition Cost Amortization As discussed under Regulatory Matters in Note 4, FirstEnergy, OE, CEI and TE amortize transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover allowed transition costs not in the financial statements prepared under GAAP. The Ohio electric utilities have revised the amortization schedules to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. This change results in higher amortization of these regulatory assets in the first several years of the transition cost recovery period, compared with the method previously applied (see summary by years included after the Above-Market Lease Costs discussion). The following table summarizes the previously reported transition cost amortization and the restated amounts under the revised method for the three months and nine months ended September 30, 2002: <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ---------------------------- ---------------------------- As Previously As As Previously As Reported Restated Reported Restated ------------- -------- ------------- -------- (In thousands) <S> <C> <C> <C> <C> OE............................ $76,019 $ 85,419 $227,221 $237,911 CEI........................... 7,967 37,907 32,763 111,743 TE............................ 11,632 29,812 25,848 77,628 ------- -------- -------- -------- Total FirstEnergy......... $95,618 $153,138 $285,832 $427,282 ======= ======== ======== ======== </TABLE> Above-Market Lease Costs In 1997, FirstEnergy was formed through a merger between OE and Centerior Energy Corp. The merger was accounted for as an acquisition of Centerior, the parent company of CEI and TE, under the purchase accounting rules of APB 16. In connection with the reassessment of the accounting for the transition plan, FirstEnergy reassessed its accounting for the Centerior purchase and determined that above market lease liabilities should have been recorded at the time of the merger. Accordingly, as of 2002, FirstEnergy recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which CEI and TE had previously entered into sale-leaseback arrangements. CEI and TE recorded an increase in goodwill related to the above market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional liability would have increased goodwill at the date of the merger. The corresponding impact of the above market lease liabilities for the Bruce Mansfield Plant were recorded as regulatory assets because SFAS 71 had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided for under the transition plan. The total above market lease obligation of $722 million (CEI-$611 million; TE-$111 million) associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017. The additional goodwill has been recorded on a net basis, reflecting amortization that would have been recorded through 2001 when goodwill amortization ceased with the adoption of SFAS 142. The total above market lease obligation of $755 million (CEI-$457 million, TE-$298 million) associated with the Bruce Mansfield Plant is being amortized through the end of 2016. Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation. Beginning in 2001, the remaining unamortized regulatory asset would have been included in CEI's and TE's amortization schedules for regulatory assets and amortized through the end of the recovery period - approximately 2009 for CEI and 2007 for TE. FirstEnergy reflected the net impact of the accounting for these items for the period from the merger in 1997 through 2001 in the 2002 financial statements. The cumulative impact to net income recorded in 2002 related to these prior periods increased net income by $5.9 million in the restated 2002 financial statements and was reflected as a reduction in other operating expenses. In addition, the impact changed the following balances in the consolidated balance sheet as of January 1, 2002: Increase (Decrease) (In Thousands) Goodwill.............................. $ 381,780 Regulatory assets..................... 636,100 ---------- Total assets.......................... $1,017,880 ========== Other current liabilities............. 84,600 Deferred income taxes................. (262,580) Deferred investment tax credits....... (828) Other deferred credits................ 1,190,800 ---------- Total liabilities..................... $1,011,992 ========== Retained earnings..................... $ 5,888 ========== The adjustments described above are anticipated to result in a decrease in reported net income through 2005 and an increase in net income for the period 2006 through 2017, the end of the lease term for Beaver Valley Unit 2. The schedule below shows the estimated impact on pre-tax income of these adjustments for 2001 through 2009. <TABLE> <CAPTION> Above-Market Leases ------------------------------------------ Transition Cost Amortization Effect on ---------------------------- Goodwill Pre-Tax Year Original Revised Change Amortization (a) Reversal Amortization Income ---- -------- ------- ------ ------------ -------- ------------ ------ <S> <C> <C> <C> <C> <C> <C> <C> 2001-2002 $ 792 $ 947 $(155) $(170) $287 $(44) $(82) 2003 514 582 (68) (103) 85 (86) 2004 628 668 (40) (118) 85 (73) 2005 813 777 36 (136) 85 (16) 2006 328 295 33 (83) 85 35 2007 200 136 64 (77) 85 72 2008 213 107 106 (56) 85 135 2009 55 31 24 (12) 85 97 -------- -------- ------ $3,543 $3,543 $ -- ====== ====== ======= <FN> (a) This represents the additional amortization related to the regulatory assets recognized in connection with the above-market lease for the Bruce Mansfield Plant discussed above. </FN> </TABLE> 6
The effects of these changes on the Consolidated Statements of Income previously reported for the three months ended March 31, 2003, were disclosed in Amendment No. 1 to FirstEnergy's, OE's, CEI's and TE's Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2003. The effects of these changes on the respective Consolidated Statements of Income previously reported for the three months and nine months ended September 30, 2002 are as follows: <TABLE> <CAPTION> FirstEnergy - ----------- Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ----------------------------- ---------------------------- As Previously As As Previously As Reported Restated Reported Restated ------------- ---------- ------------- ---------- (In thousands, except per share amounts) <S> <C> <C> <C> <C> Revenues................................. $3,451,184 $3,451,184 $9,203,035 $9,203,035 Expenses ................................ 2,681,668 2,724,018 7,275,711 7,359,019 ---------- ---------- ---------- ---------- Income before interest and income taxes . 769,516 727,166 1,927,324 1,844,016 Net interest charges..................... 220,397 220,397 749,401 749,401 Income taxes............................. 238,864 221,924 517,865 483,604 ---------- ---------- ---------- ---------- Net income............................... $ 310,255 $ 284,845 $ 660,058 $ 611,011 ========== ========== ========== ========== Basic earnings per share of common stock. ................................. $1.06 $.97 $2.25 $2.08 Diluted earnings per share of common stock .................................. $1.05 $.97 $2.24 $2.08 </TABLE> <TABLE> <CAPTION> OE - -- Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ----------------------------- ---------------------------- As Previously As As Previously As Reported Restated Reported Restated ------------- ---------- ------------- ---------- (In thousands) <S> <C> <C> <C> <C> Operating revenues....................... $ 813,296 $ 813,296 $2,265,645 $2,265,645 Operating expenses and taxes............. 658,794 664,518 1,875,475 1,876,036 ---------- ---------- ---------- ---------- Operating income ........................ 154,502 148,778 390,170 389,609 Other income............................. 14,212 14,212 29,811 29,811 Net interest charges..................... 33,695 33,695 110,776 110,776 ---------- ---------- ---------- ---------- Net income............................... 135,019 129,295 309,205 308,644 Preferred stock dividend requirements.... 658 658 5,851 5,851 ---------- ---------- ---------- ---------- Earnings on common stock................. $ 134,361 $ 128,637 $ 303,354 $ 302,793 ========== ========== ========== ========== </TABLE>
<TABLE> <CAPTION> CEI - --- Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ----------------------------- ---------------------------- As Previously As As Previously As Reported Restated Reported Restated ------------- ---------- ------------- ---------- (In thousands) <S> <C> <C> <C> <C> Operating revenues....................... $ 538,879 $ 538,879 $1,426,730 $1,435,030 Operating expenses and taxes............. 410,387 418,967 1,130,162 1,150,518 ---------- ---------- ---------- ---------- Operating income ........................ 128,492 119,912 296,568 284,512 Other income............................. 5,562 5,562 14,159 14,159 Net interest charges..................... 47,263 47,263 141,880 141,880 ---------- ---------- ---------- ---------- Net income............................... 86,791 78,211 168,847 156,791 Preferred stock dividend requirements.... 3,149 3,149 14,459 12,759 ---------- ---------- ---------- ---------- Earnings on common stock................. $ 83,642 $ 75,062 $ 154,388 $ 144,032 ========== ========== ========== ========== </TABLE> <TABLE> <CAPTION> TE - -- Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ----------------------------- ---------------------------- As Previously As As Previously As Reported Restated Reported Restated ------------- ---------- ------------- ---------- (In thousands) <S> <C> <C> <C> <C> Operating revenues....................... $ 269,857 $ 269,857 $ 764,331 $ 772,731 Operating expenses and taxes............. 244,815 251,670 695,472 716,207 ---------- ---------- ---------- ---------- Operating income ........................ 25,042 18,187 68,859 56,524 Other income............................. 4,033 4,033 12,119 12,119 Net interest charges..................... 14,463 14,463 44,031 44,031 ---------- ---------- ---------- ---------- Net income............................... 14,612 7,757 36,947 24,612 Preferred stock dividend requirements.... 2,211 2,211 9,145 9,145 ---------- ---------- ---------- ---------- Earnings on common stock................. $ 12,401 $ 5,546 $ 27,802 $ 15,467 ========== ========== ========== ========== </TABLE> 7
The effects of these changes on the respective Consolidated Statements of Cash Flows previously reported for the three months and nine months ended September 30, 2002 are as follows: <TABLE> <CAPTION> FE - -- Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ----------------------------- ---------------------------- As Previously As As Previously As Reported Restated (1) Reported Restated (1) ------------- ---------- ------------- -------- (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net income............................... $ 310,255 $ 284,845 $ 660,058 $ 611,011 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization.......................... 253,917 310,417 767,450 920,196 Nuclear fuel and lease amortization...... 20,191 20,191 60,754 60,754 Other amortization....................... (5,381) (5,381) (13,304) (13,304) Deferred costs recoverable as regulatory assets ...................... (152,336) (145,336) (291,406) (291,406) Deferred income taxes.................... 37,831 20,891 81,252 33,391 Investment tax credits................... (6,767) (6,767) (20,480) (20,480) Cumulative effect of accounting change (Note 5) ............................... -- -- (45,300) -- .......................................... Receivables.............................. (67,608) (67,608) (151,175) (157,670) Materials and supplies................... (18,388) (18,388) (21,967) (21,967) Accounts payable......................... 47,888 47,888 85,662 92,650 Accrued taxes............................ 16,687 16,687 103,407 103,407 Accrued interest......................... 79,063 79,063 59,507 59,507 Other.................................... 153,065 131,915 120,166 18,535 ---------- ---------- ---------- ---------- Net cash provided from operating activities .......................... $ 668,417 $ 668,417 $1,394,624 $1,394,624 ---------- ---------- ---------- ---------- </TABLE> <TABLE> <CAPTION> OE - -- Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ----------------------------- ---------------------------- As Previously As As Previously As Reported Restated (1) Reported Restated (1) ------------- ---------- ------------- -------- (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net income............................... $ 135,019 $ 129,295 $ 309,205 $ 308,644 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization ......................... 82,691 90,991 266,342 273,932 Nuclear fuel and lease amortization...... 12,389 12,389 35,924 35,924 Deferred income taxes.................... (9,782) (12,682) (31,838) (39,838) Investment tax credits................... (3,751) (3,427) (11,286) (10,315) Receivables.............................. (18,352) (18,352) 14,451 14,451 Materials and supplies................... (3,699) (3,699) (8,499) (8,499) Accounts payable......................... 18,690 18,690 (771) (771) Accrued taxes............................ 16,302 16,302 222,562 222,562 Other.................................... 44,883 44,883 39,240 39,240 ---------- ---------- ---------- ---------- Net cash provided from operating activities .......................... $ 274,390 $ 274,390 $ 835,330 $ 835,330 ---------- ---------- ---------- ---------- </TABLE> 8
<TABLE> <CAPTION> CEI - --- Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ----------------------------- ---------------------------- As Previously As As Previously As Reported Restated (1) Reported Restated (1) ------------- ---------- ------------- ---------- (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net income............................... $ 86,791 $ 78,211 $ 168,847 $ 156,791 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization ......................... 17,846 47,646 74,650 153,250 Nuclear fuel and lease amortization...... 5,037 5,037 15,821 15,821 Other amortization....................... (3,937) (3,937) (12,104) (12,104) Deferred income taxes.................... 6,812 736 19,912 3,582 Investment tax credits................... (1,015) (1,159) (3,046) (3,472) Receivables.............................. 3,274 3,274 (28,383) (36,683) Materials and supplies................... (1,786) (1,786) (4,992) (4,992) Accounts payable......................... (23,141) (23,141) 3,238 3,238 Other.................................... 23,518 8,518 9,930 (31,558) ---------- ---------- ---------- ---------- Net cash provided from operating activities .......................... $ 113,399 $ 113,399 $ 243,873 $ 243,873 ---------- ---------- ---------- ---------- </TABLE> <TABLE> <CAPTION> TE - -- Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ----------------------------- ---------------------------- As Previously As As Previously As Reported Restated (1) Reported Restated (1) ------------- ---------- ------------- ---------- (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net Income............................... $ 14,612 $ 7,757 $ 36,947 $ 24,612 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization ......................... 23,413 41,813 64,529 116,929 Nuclear fuel and lease amortization...... 2,765 2,765 9,009 9,009 Deferred income taxes.................... (5,911) (11,266) (19) (14,346) Investment tax credits................... (414) (454) (1,387) (1,507) Receivables.............................. 22,359 22,359 23,619 15,219 Materials and supplies................... (2,150) (2,150) (3,970) (3,970) Accounts payable......................... 26,894 26,894 20,545 18,845 Accrued sale leaseback costs............. 8,905 2,755 (19,549) (37,999) Other.................................... 7,556 7,556 9,597 12,529 ---------- ---------- ---------- ---------- Net cash provided from operating activities .......................... $ 98,029 $ 98,029 $ 139,321 $ 139,321 ---------- ---------- ---------- ---------- <FN> (1) The restated cash flow amounts included above in the three-month and nine-month periods of 2002 do not reflect the changes in the current year presentation included in the Consolidated Statements of Cash Flows. </FN> </TABLE> 2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES: Capital Expenditures FirstEnergy's current forecast reflects expenditures of approximately $3.1 billion (OE-$268 million, CEI-$312 million, TE-$169 million, Penn-$123 million, JCP&L-$462 million, Met-Ed-$288 million, Penelec-$328 million, ATSI-$131 million, FES-$823 million and other subsidiaries-$147 million) for property additions and improvements from 2003-2007, of which approximately $732 million (OE-$80 million, CEI-$102 million, TE-$62 million, Penn-$43 million, JCP&L-$103 million, Met-Ed-$37 million, Penelec-$40 million, ATSI-$17 million, FES-$163 million and other subsidiaries-$85 million) is applicable to 2003. Investments for additional nuclear fuel during the 2003-2007 period are estimated to be approximately $481 million (OE-$57 million, CEI-$42 million, TE-$21 million, Penn-$38 million and FES-$323 million), of which approximately $65 million (OE-$25 million, CEI-$14 million, TE-$9 million and Penn-$17 million) applies to 2003. Guarantees and Other Assurances As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of September 30, 2003, outstanding guarantees and other assurances aggregated $1.036 billion. 9
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 $956.0 million as of September 30, 2003 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $15.6 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions. Various energy supply contracts contain credit enhancement provisions in the form of cash collateral or letters of credit in the event of a reduction in credit rating below investment grade. These provisions vary and typically require more than one rating reduction to fall below investment grade by Standard & Poor's or Moody's Investors Service to trigger additional collateralization by FirstEnergy. As of September 30, 2003, rating-contingent collateralization totaled $64.2 million. FirstEnergy monitors these collateralization provisions and updates its total exposure monthly. Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $159 million, which is included in the construction forecast provided under "Capital Expenditures" for 2003 through 2007. The Companies are required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies believe they are in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that required compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals for the D.C. Circuit found constitutional and other defects in the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating ultra-fine particulates but found defects in the new NAAQS rules for ozone and decided that the EPA must revise those rules. The future cost of compliance with these regulations may be substantial and will depend if and how they are ultimately implemented by the states in which the Companies operate affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability 10
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 April 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 Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been recorded as of September 30, 2003. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. The Companies have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2003, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable societal benefits charge. The Companies have total accrued liabilities aggregating approximately $50.4 million (JCP&L-$47.9 million, CEI-$2.5 million, TE-$0.2 million, Met-Ed-$0.2 million and Penelec-$0.2 million) as of September 30, 2003. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy believes it is in material compliance with existing regulations but is unable to predict whether environmental regulations will change and what, if any, the effects of such change would be. Other Commitments and Contingencies GPU made significant investments in foreign businesses and facilities through its GPU Capital and GPU Power subsidiaries. Although FirstEnergy attempts to mitigate its risks related to foreign investments, it faces additional risks inherent in operating in such locations, including foreign currency fluctuations. EI Barranquilla, a wholly owned subsidiary of GPU Power, is a 28.67% equity investor in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA), which owns a Colombian independent power generation project. GPU Power was committed through September 30, 2003, under certain circumstances, to make additional standby equity contributions to TEBSA of $21.3 million, which FirstEnergy has guaranteed. The total outstanding senior debt of the TEBSA project is $215 million as of September 30, 2003. FirstEnergy believes it has met the obligation and has requested release from lenders. The banks' decision is pending. The lenders include the Overseas Private Investment Corporation, US Export Import Bank and a commercial bank syndicate. FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6.0 million (subject to escalation) under the project's operations and maintenance agreement. FirstEnergy provided the TEBSA project lenders a $50 million letter of credit (LOC) (under FirstEnergy's existing $250 million LOC capacity available as part of a $1.5 billion FirstEnergy credit facility) to obtain TEBSA lender consent as substitute collateral for the release of the assets for FirstEnergy to abandon its Argentina operations, Emdersa (see Note 3 below). Power Outage On August 14, 2003, eight states and southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. The cause of the outage has not been 11
determined. FirstEnergy continues to accumulate data and evaluate the status of its electrical system prior to and during the outage event. On September 12, 2003, the U.S./Canada Power Outage Task Force (Task Force) investigating the August 14 outage released a timeline of events. The timeline presented the sequence of events that occurred on major transmission lines (230 kilovolts or greater) and at large power plants beginning at approximately noon through approximately 4:00 PM, preceding the outage. This timeline did not attempt to present or explain the linkages between the sequence of events. Determining the specific causes of the events and their relation to the outage will require more time to analyze by the Task Force. The Task Force is expected to release its interim report on November 18, 2003. Legal Matters As of October 14, 2003, ten individual shareholder-plaintiffs have filed separate complaints against FirstEnergy alleging various securities law violations. The bases for these complaints vary but include alleged violations arising out of the power outage, the extended outage at Davis-Besse, and the restatement of earnings, all described herein. FirstEnergy is reviewing the suits that have been served in preparation for a responsive pleading. FirstEnergy is, however, aware that in each case, the plaintiffs are seeking certification from the court to represent a class of similarly situated shareholders. In addition, four shareholder-plaintiffs have filed "shareholder derivative" actions against the members of the Board of Directors, and FirstEnergy as a nominal defendant, asserting rights of the corporation itself. The complaints allege violations of fiduciary duties as a result of, generally, the same events described in the securities lawsuits described herein. Furthermore, five lawsuits - three in Ohio state courts, two in New York state courts - have been filed seeking damages relating to the August 14, 2003 power outage. The two New York actions name FirstEnergy as one of several defendants and have been noticed but not served. Additionally, a complaint has been filed with the PUCO by United States Congressman Dennis Kucinich, alleging that as a result of several events, including the August 14, 2003 power outage and the extended outage at Davis-Besse, both described herein, the Company has failed to provide adequate and reasonable service to its customers. That complaint asks, among other things, that another electric supplier be authorized to provide service within the Ohio Utilities' certified territories. FirstEnergy believes that in each instance, the legal actions are without merit. FirstEnergy intends to defend these actions vigorously, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be instituted against it. In particular, if FirstEnergy were ultimately determined to have legal liability in connection with the outage, it could have a material adverse effect on FirstEnergy's financial condition and results of operations. Various lawsuits, claims and proceedings related to FirstEnergy's normal business operations are pending against it, the most significant of which are described herein. 3 - DIVESTITURES: INTERNATIONAL OPERATIONS- FirstEnergy had identified certain former GPU international operations for divestiture within one year of the merger. These operations constitute individual "lines of business" as defined in APB Opinion (APB) No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," with physically and operationally separable activities. Application of Emerging Issues Task Force (EITF) Issue No. 87-11, "Allocation of Purchase Price to Assets to Be Sold," required that expected, pre-sale cash flows, including incremental interest costs on related acquisition debt, of these operations be considered part of the purchase price allocation. Accordingly, subsequent to the merger date, results of operations and incremental interest costs related to these international subsidiaries were not included in FirstEnergy's 2001 Consolidated Statement of Income. Additionally, assets and liabilities of these international operations had been segregated under separate captions on the Consolidated Balance Sheet as of December 31, 2001 as "Assets Pending Sale" and "Liabilities Related to Assets Pending Sale." Upon completion of its merger with GPU, FirstEnergy accepted an October 2001 offer from Aquila, Inc. (formerly UtiliCorp United) to purchase Avon, FirstEnergy's wholly owned holding company for Midlands Electricity plc, for $2.1 billion (including the assumption of $1.7 billion of debt). The transaction closed on May 8, 2002 and reflected the March 2002 modification of Aquila's initial offer such that Aquila acquired a 79.9 percent equity interest in Avon for approximately $1.9 billion (including the assumption of $1.7 billion of debt). Proceeds to FirstEnergy included $155 million in cash and a note receivable for approximately $87 million (representing the present value of $19 million per year to be received over six years beginning in 2003) from Aquila for its 79.9 percent interest. FirstEnergy and Aquila together own all of the outstanding shares of Avon through a jointly owned subsidiary, with each company having an ownership voting interest. Originally, in accordance with applicable accounting guidance, the earnings of those foreign operations were not recognized in current earnings from the date of the GPU acquisition. However, as a result of the decision to retain an ownership interest in Avon in the quarter ended March 31, 2002, EITF Issue No. 90-6, "Accounting for Certain Events Not Addressed in Issue No. 87-11 relating to an Acquired Operating Unit to be Sold" required FirstEnergy to reallocate the purchase price of GPU based on amounts as of the purchase date as if Avon had never been held for sale, including reversal of the effects of having applied EITF Issue No. 87-11, to the transaction. The effect of reallocating the purchase price and reversal of the effects of EITF Issue No. 87-11, including the allocation of capitalized interest, has been reflected in the Consolidated Statement of Income 12
for the nine months ended September 30, 2002 by reclassifying certain revenue and expense amounts related to activity during the quarter ended March 31, 2002 to their respective income statement classifications for the nine-month 2002 period. See Note 1 for the effects of the change in classification. In the fourth quarter of 2002, FirstEnergy recorded a $50 million charge to reduce the carrying value of its remaining 20.1 percent interest. In the second quarter of 2003, FirstEnergy recognized an impairment of $12.6 million ($8.2 million net of tax) related to the carrying value of the note FirstEnergy had with Aquila from the initial sale of a 79.9 percent interest in Avon that occurred in May 2002. After receiving the first annual installment payment of $19 million in May 2003, FirstEnergy sold the remaining balance of its note receivable in the secondary market and received $63.2 million in proceeds on July 28, 2003. In May 2003, FirstEnergy reached an agreement to sell its 20.1 percent interest in Avon to Scottish and Southern Energy plc; subsequently, the agreement was terminated when the parties were unable to agree to terms with representatives of certain bondholders. On October 21, 2003, FirstEnergy announced it reached an agreement to sell its 20.1 percent interest in Avon to a subsidiary of Powergen UK plc, as part of a transaction to include Aquila's 79.9 percent interest. Under terms of the agreement, FirstEnergy would receive approximately $8 million. The sale is contingent upon regulatory approval and reaching agreement with bondholders representing 95% of the aggregate principal amount of the bonds. The holders of approximately half of the outstanding bonds have given their approval. GPU's former Argentina operations were also identified by FirstEnergy for divestiture within one year of the merger. FirstEnergy determined the fair value of Emdersa, based on the best available information as of the date of the merger. Subsequent to that date, a number of economic events occurred in Argentina which affected FirstEnergy's ability to realize Emdersa's estimated fair value. These events included currency devaluation, restrictions on repatriation of cash, and the anticipation of future asset sales in that region by competitors. FirstEnergy did not reach a definitive agreement to sell Emdersa as of December 31, 2002. Therefore, these assets were no longer classified as "Assets Pending Sale" on the Consolidated Balance Sheet as of December 31, 2002. Additionally, under EITF Issue No. 90-6, FirstEnergy recorded in the fourth quarter of 2002 a one-time, non-cash charge included as a "Cumulative Adjustment for Retained Businesses Previously Held for Sale" on its 2002 Consolidated Statement of Income related to Emdersa's cumulative results of operations from November 7, 2001 through September 30, 2002. The amount of this one-time, after-tax charge was $93.7 million, or $0.32 per share of common stock (comprised of $108.9 million in currency transaction losses arising principally from U.S. dollar denominated debt, offset by $15.2 million of operating income). In October 2002, FirstEnergy began consolidating the results of Emdersa's operations in its financial statements. In addition to the currency transaction losses of $108.9 million, FirstEnergy also recognized a currency translation adjustment (CTA) in other comprehensive income (OCI) of $91.5 million as of December 31, 2002, which reduced FirstEnergy's common stockholders' equity. This adjustment represented the impact of translating Emdersa's financial statements from its functional currency to the U.S. dollar for GAAP financial reporting. On April 18, 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. As a result of the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67.4 million, or $0.23 per share of common stock in the second quarter of 2003. This charge is the result of realizing the CTA losses through current period earnings ($89.8 million, or $0.30 per share), partially offset by the gain recognized from abandoning FirstEnergy's investment in Emdersa ($22.4 million, or $0.07 per share). Since FirstEnergy had previously recorded $89.8 million of CTA adjustments in OCI, the net effect of the $67.4 million charge was an increase in common stockholders' equity of $22.4 million. The $67.4 million charge does not include the anticipated income tax benefits related to the abandonment, which were fully reserved during the second quarter of 2003. FirstEnergy anticipates tax benefits of approximately $129 million, of which $50 million would increase net income in the period that it becomes probable those benefits will be realized. The remaining $79 million of tax benefits would reduce goodwill recognized in connection with the acquisition of GPU. SALE OF GENERATING ASSETS- In November 2001, FirstEnergy reached an agreement to sell four coal-fired power plants totaling 2,535 megawatts (MW) to NRG Energy Inc. On August 8, 2002, FirstEnergy notified NRG that it was canceling the agreement because NRG stated that it could not complete the transaction under the original terms of the agreement. FirstEnergy also notified NRG that FirstEnergy reserves the right to pursue legal action against NRG, its affiliate and its parent, Xcel Energy for damages, based on the anticipatory breach of the agreement. In May 2003, NRG filed voluntary bankruptcy petitions in U.S. Bankruptcy Court in the Southern District of New York. On November 13, 2003, FirstEnergy announced it had reached an agreement for settlement of its claim against NRG, subject to U.S. Bankruptcy Court approval and required authorization from the FERC. Under NRG's proposed Plan of Reorganization, FirstEnergy, as an unsecured 13
creditor, could receive an estimated settlement of approximately $198 million, with payment in the form of cash (12%), notes (15.2%) and new NRG common stock (72.8%). In December 2002, FirstEnergy decided to retain ownership of these plants after reviewing other bids it subsequently received from other parties who had expressed interest in purchasing the plants. Since FirstEnergy did not execute a sales agreement by year-end, it reflected approximately $74 million ($43 million net of tax) of previously unrecognized depreciation and other transaction costs in the fourth quarter of 2002 related to these plants from November 2001 through December 2002 on its Consolidated Statement of Income. 4 - REGULATORY MATTERS: In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in the Companies' respective state regulatory plans: o allowing the Companies' electric customers to select their generation suppliers; o establishing provider of last resort (PLR) obligations to customers in the Companies' service areas; o allowing recovery of potentially stranded investment (sometimes referred to as transition costs); o itemizing (unbundling) the current price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; o deregulating the Companies' electric generation businesses; and o continuing regulation of the Companies' transmission and distribution systems. Ohio In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. In July 2000, the PUCO approved FirstEnergy's transition plan for OE, CEI and TE (Ohio Companies) as modified by a settlement agreement with major parties to the transition plan. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation" to OE's generation business and the nonnuclear generation businesses of CEI and TE was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $4.0 billion net of deferred income taxes (OE-$1.6 billion, CEI-$1.6 billion and TE-$0.8 billion) and transition costs related to regulatory assets as filed of $2.9 billion net of deferred income taxes (OE-$1.0 billion, CEI-$1.4 billion and TE-$0.5 billion), with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.4 billion, net of deferred income taxes, (OE-$1.0 billion, CEI-$0.2 billion and TE-$0.2 billion) of impaired generating assets recognized as regulatory assets as described further below, $2.4 billion, net of deferred income taxes, (OE-$1.2 billion, CEI-$0.4 billion and TE-$0.8 billion) of above market operating lease costs and $0.8 billion, net of deferred income taxes, (CEI-$0.5 billion and TE-$0.3 billion) of additional plant costs that were reflected on CEI's and TE's regulatory financial statements. Also as part of the settlement agreement, FirstEnergy is giving preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 MW of generation capacity through 2005 at established prices for sales to the Ohio Companies' retail customers. Customer prices are frozen through the five-year market development period, which runs through the end of 2005, except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003, the Ohio Companies were authorized increases in annual revenues aggregating approximately $50 million (OE-$41 million, CEI-$4 million and TE-$5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation. FirstEnergy's Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be 14
accomplished by extending the respective transition cost recovery period. If the customer shopping goals established in the agreement had not been achieved by the end of 2005, the transition cost recovery periods could have been shortened for OE, CEI and TE to reduce recovery by as much as $500 million (OE-$250 million, CEI-$170 million and TE-$80 million). The Ohio Companies achieved all of their required 20% customer shopping goals in 2002. Accordingly, FirstEnergy believes that there will be no regulatory action reducing the recoverable transition costs. On October 21, 2003, the Ohio Companies 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 supply and continuing FirstEnergy's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service, including PLR responsibility, for FirstEnergy's Ohio 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 FirstEnergy's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity as discussed above. In order to facilitate supply planning, FirstEnergy has requested that the PUCO rule on this proposal by December 31, 2003. Under the proposed plan, FirstEnergy is requesting: o Extension of the transition cost amortization period for OE from 2006 to 2007; for CEI from 2008 to 2009 and for TE from mid-2007 to 2008; o Deferral of new regulatory assets and deferral of interest costs on the shopping incentive and other new deferrals; o Ability to initiate a request to increase generation rates only under certain limited conditions. As a result of the Ohio Companies' October 21 filing, the PUCO entered an order on October 28, 2003 setting forth the discovery schedule related to the application with hearings scheduled to begin December 3, 2003. 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 societal benefits charge (SBC) to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable market transition charge (MTC) primarily to recover stranded costs. The NJBPU has deferred making a final determination of the net proceeds and stranded costs related to prior generating asset divestitures until JCP&L's request for an Internal Revenue Service (IRS) ruling regarding the treatment of associated federal income tax benefits is acted upon. Should the IRS ruling support the return of the tax benefits to customers, there would be no effect to FirstEnergy's or JCP&L's net income since the contingency existed prior to the merger. In addition, the Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. In 2002, JCP&L received NJBPU authorization to issue $320 million of transition bonds to securitize the recovery of these costs and which provided for a usage-based non-bypassable transition bond charge (TBC) and for the transfer of the bondable transition property to another entity. JCP&L sold the transition bonds through its wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 - those bonds are recognized on the Consolidated Balance Sheet. JCP&L's PLR obligation to provide basic generation service (BGS) to non-shopping customers is supplied almost entirely from contracted and open market purchases. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under nonutility generation (NUG) agreements exceed amounts collected through BGS and MTC rates. As of September 30, 15
2003, the accumulated deferred cost balance totaled approximately $440 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 submitted two rate filings with the NJBPU in August 2002. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization discussed above. 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 percent on JCP&L's rate base for 6 to 12 months. During that period, JCP&L will initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75 percent or decrease it to 9.25 percent, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The 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 charge. 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 nine months ended September 30, 2003, aggregating $172 million ($103 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 which is expected to be issued in the fourth quarter of 2003. In February 2003, the NJBPU approved the BGS auction results for the period beginning August 1, 2003. The auction covered a fixed price bid (applicable to all residential and smaller commercial and industrial customers) and an hourly price bid (applicable to all large industrial customers) process. JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balances. Pennsylvania The PPUC authorized 1998 rate restructuring plans for Penn, Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Similar to JCP&L's situation, if the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income since the contingency existed prior to the merger. 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 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 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. 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 Administrative Law Judge 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 competitive transition charge (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. 16
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 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. Met-Ed and Penelec are considering filing an appeal to the Commonwealth Court on the PPUC orders as well. 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 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 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 assigned their PLR responsibility to their FES affiliate through a wholesale power sale agreement. The PLR sale currently runs through December 2003 and will be automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES assumed the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other 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. 5 - NEW ACCOUNTING STANDARDS ADOPTED: SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the beginning of the first interim period beginning after June 15, 2003 (FirstEnergy's third quarter of 2003) for all other financial instruments. Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy reclassified as debt the preferred stock of consolidated subsidiaries subject to mandatory redemptions with a carrying value of approximately $17.5 million ($4.0 million for CEI and $13.5 million for Penn) as of September 30, 2003. Subsidiary-obligated mandatorily redeemable preferred securities of $285 million ($100 million for CEI, $93 million for Met-Ed and $92 million for Penelec) were also reclassified and included in long-term debt as of September 30, 2003. As required by SFAS 150, the preferred securities subject to mandatory redemption were not restated as long-term debt on the December 31, 2002 balance sheet. Adoption of SFAS 150 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. Dividends on preferred stock subject to mandatory redemption on CEI and Penn's respective Consolidated Statements of Income, which were not included in net interest charges prior to the adoption of SFAS 150, were included in net interest charges for the three months ended September 30, 2003. CEI, Met-Ed and Penelec created statutory business trusts to issue the preferred securities of $285 million discussed above. The continued consolidation of the issuer trusts and the appropriate balance sheet classification of the trust preferred securities is currently under review pursuant to FIN 46 (see Note 6). Upon the implementation of FIN 46 effective December 31, 2003, these trusts would be deconsolidated if CEI, Met-Ed and Penelec were not the primary beneficiaries of the related trusts. Rather than recording a liability for the trust preferred securities as discussed above, FirstEnergy, CEI, Met-Ed and Penelec would reflect liabilities for the notes payable to the respective trusts, which are 17
currently eliminated in consolidation. The deconsolidation of the trusts would result in an increase to total assets and liabilities of $9.3 million ($3.1 million for each of CEI, Met-Ed and Penelec) for the investment in the trusts. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS 133 for decisions made by the Derivative Implementation Group (DIG), as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for reporting periods beginning before June 15, 2003, that continue to be applied based on their original effective dates. Adoption of SFAS 149 did not have a material impact on the Companies' financial statements. SFAS 143, "Accounting for Asset Retirement Obligations" In January 2003, FirstEnergy implemented SFAS 143 which provides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires that the fair value of a liability for an asset retirement obligation (ARO) be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003 asset retirement costs were recorded in the amount of $602 million as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The ARO liability at the date of adoption was $1.107 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 $1.244 billion. FirstEnergy expects substantially all nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn would be recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for these operating companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $174.7 million increase to income, $102.1 million net of tax, or $0.35 per share of common stock (basic and diluted). FirstEnergy recorded an ARO for nuclear decommissioning ($1.096 billion) of the Beaver Valley 1, Beaver Valley 2, Davis-Besse, Perry, and TMI-2 nuclear generating facilities with the remaining ARO related to the Bruce Mansfield Plant's sludge impoundment facilities and two coal ash disposal sites. The Companies maintain nuclear decommissioning trust funds, which had balances as of September 30, 2003 of $1.230 billion. This amount represents the fair value of the assets that are legally restricted for purposes of settling the nuclear decommissioning ARO. The following table provides the beginning and ending aggregate carrying amount of the total ARO and the changes to the balance during the third quarter and the first nine months of 2003. <TABLE> <CAPTION> Periods Ended September 30, 2003 ---------------------------------- ARO Reconciliation Three Months Nine Months - --------------------------------------------------------------------------------------- (In millions) <S> <C> <C> Balance at beginning of period .................... $1,143 $1,107 Liabilities incurred in the current period......... -- -- Liabilities settled in the current period.......... -- -- Accretion expense.................................. 18 54 Revisions in estimated cash flows.................. -- -- - ------------------------------------------------------------------------------------ Balance at end of period........................... $1,161 $1,161 - ------------------------------------------------------------------------------------ </TABLE> The following table provides the year-end balance of the ARO related to nuclear decommissioning and sludge impoundment for 2002, as if SFAS 143 had been adopted on January 1, 2002. Adjusted ARO Reconciliation - --------------------------------------------------------------------------- (In millions) Beginning balance as of January 1, 2002......................... $1,042 Accretion 2002.................................................. 65 - --------------------------------------------------------------------------- Ending balance as of December 31, 2002.......................... $1,107 - --------------------------------------------------------------------------- In accordance with SFAS 143, FirstEnergy ceased the accounting practice of depreciating non-regulated generation assets using a cost of removal component in the depreciation rates. This practice recognizes accumulated depreciation in excess of the historical cost of an asset, because the removal cost exceeds the estimated salvage value. The change in accounting resulted in a $60 million credit to income as part of the SFAS 143 cumulative effect adjustment. Beginning in 2003 cost of removal related to non-regulated generation assets is charged to expense rather than charged to the accumulated provision for depreciation. In accordance with SFAS 71, the regulated plant assets will continue the accounting practice of depreciating assets using a cost of removal component in the depreciation rates. The net removal cost credit balance included in the accumulated provision for depreciation as of September 30, 2003 was approximately $314 million. The following table provides the effect on income as if the accounting for SFAS 143 had been applied during the third quarter and first nine months of 2002. <TABLE> <CAPTION> Period Ended September 30, 2002 Effect of the Change in Accounting ------------------------------- Principle Applied Retroactively to 2002 Three Nine --------------------------------------- Months Months ------ ------ (Restated - see Note 1) (In millions) <S> <C> <C> Reported net income............................. $ 285 $ 611 ---------------------------------------------------------------------------- Increase(Decrease): Elimination of decommissioning expense.......... 26 78 Depreciation of asset retirement cost........... (1) (2) Accretion of ARO liability...................... (10) (28) Income tax effect............................... (6) (20) ---------------------------------------------------------------------------- Net earnings increase........................... 9 28 ---------------------------------------------------------------------------- Net income adjusted............................. $ 294 $ 639 ============================================================================ Basic earnings per share of common stock: Net income as previously reported............... $0.97 $2.08 Adjustment for effect of change in accounting principle applied retroactively.... .03 0.10 ---------------------------------------------------------------------------- Net income adjusted............................. $1.00 $2.18 ============================================================================ Diluted earnings per share of common stock: Net income as previously reported............... $0.97 $2.08 Adjustment for effect of change in accounting principle applied retroactively.... 0.03 0.09 ---------------------------------------------------------------------------- Net income adjusted............................. $1.00 $2.17 ============================================================================ </TABLE> EITF Issue No. 01-8, "Determining Whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if: (1) it identifies specific property, plant or equipment (explicitly or implicitly); and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus is to be applied prospectively to arrangements committed to, modified or acquired through a business combination. The adoption of this consensus as of July 1, 2003 did not impact FirstEnergy's financial statements. EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" In October 2002, the EITF reached a consensus that for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour (KWH) sales and purchases on energy trading contracts must be shown on a net basis in the Consolidated Statements of Income. Prior to its adoption for 2002 year end reporting, FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Comparative quarterly disclosures and the Consolidated Statements of Income for revenues and expenses have been reclassified for 2002 to conform with the revised presentation. In addition, the related KWH sales and purchases statistics described under Management's Discussion and Analysis of Results of Operations and Financial Condition were reclassified. The following table displays the impact of changing to a net presentation for FirstEnergy's energy trading operations. 19
<TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 --------------------- --------------------- 2002 Impact of Recording Energy Trading Net Revenues Expenses Revenues Expenses - ----------------------------------------------------------------------------------------------- Restated Restated (See Note 1) (See Note 1) (In millions) (In millions) <S> <C> <C> <C> <C> Total as originally reported.............. $3,572 $2,845 $9,414 $7,570 Adjustment................................ (121) (121) (211) (211) - ------------------------------------------------------------------------------------------------ Total as currently reported............... $3,451 $2,724 $9,203 $7,359 =============================================================================================== </TABLE> 6 - NEW ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED: FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". This Interpretation requires the consolidation of a variable interest entity (VIE) by an enterprise if that enterprise either absorbs a majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns as a result of ownership, contractual or other financial interests in the VIE. Currently, entities are generally consolidated by an enterprise that has a controlling financial interest through ownership of a majority voting interest in the entity. FIN 46 defines a VIE as an entity in which equity investors do not have the characteristics of a controlling financial interest nor have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. VIE's created after January 31, 2003, are immediately subject to the provisions of FIN 46. The FASB recently deferred implementation of FIN 46 for VIE's created before February 1, 2003, until the first reporting period ending after December 15, 2003 (FirstEnergy's quarter ending December 31, 2003.) FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements which fall within the scope of this interpretation and which meet the definition of a VIE in accordance with FIN 46. In addition to the two entities created to refinance debt discussed below, the Company is evaluating its interest in the owner trusts that acquired certain interests in the Perry Plant, Beaver Valley Unit 2 and the Bruce Mansfield Plant. 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. FirstEnergy is exposed to losses under the sale-leaseback agreements upon the occurrence of certain contingent events that we consider unlikely to occur. The Company's maximum exposure to loss is currently estimated to be $2.0 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the plants worthless. Under the sale and leaseback agreements, FirstEnergy has minimum undiscounted net lease payments of $2.6 billion that would not be payable if the casualty value payments are made. In addition, the Company has recorded above market lease obligations of $1.1 billion related to the Bruce Mansfield Plant and Beaver Valley Unit 2 as of September 30, 2003 (see Note 1) related to the acquisition by FirstEnergy of CEI and TE. FirstEnergy currently believes that it will consolidate two VIE's created in 1996 and 1997 to refinance debt in connection with the above sale and leaseback transactions. In 1996, the PNBV Capital Trust issued equity and notes to fund the acquisition of a portion of the collateralized lease bonds that had been issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by the PNBV Trust. Ownership of the trust 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 the trust as of December 31, 2002 would have changed the PNBV trust investment of $389 million to an investment in collateralized lease bonds of $401 million. The increase in $12 million would have represented the minority interest in the total assets of the trust. In 1997, CEI and TE established the Shippingport Capital Trust to purchase all of the lease obligation bonds issued by the owner trusts in the Bruce Mansfield Plant sale and leaseback transactions. CEI and TE acquired all of the notes issued by Shippingport Capital Trust. The equity ownership of this trust includes a 0.34% interest held by Toledo Edison Capital Corporation (TECC), a wholly owned subsidiary of TE, and a 2.25% interest and a 2.60% interest held by unaffiliated third parties. The assets and liabilities of the trust are currently included on a proportionate basis in the financial statements of CEI and TE. Adoption of FIN 46 will not impact FirstEnergy with respect to this trust, but may result in reporting all of the trust assets and liabilities on the books of CEI. As described in Note 1, the consolidated financial statements of FirstEnergy, CEI, Met-Ed and Penelec currently include several trusts that have sold trust preferred securities in which FirstEnergy is not the primary beneficiary. Pending further guidance from the FASB that would indicate otherwise, these entities may not be consolidated in FirstEnergy's financial statements as of December 31, 2003. The deconsolidation would result in an 20
increase to total assets and liabilities of $9.3 million ($3.1 million for each of CEI, Met-Ed and Penelec) for the investment in the trusts. The FASB continues to provide additional guidance on implementing FIN 46 and recently proposed modifications and clarifications with a comment period ending December 1, 2003. As this guidance is finalized, the Company will continue to assess the accounting and disclosure impact of FIN 46 with respect to the VIE's discussed above as well as other potential VIE's. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003, which would correspond to FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence of a general index, such as the Consumer Price Index, in a contract would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. FirstEnergy is currently assessing the new guidance but does not anticipate any material impact on its financial statements. 7 - 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, which includes eight electric utility operating companies in Ohio, Pennsylvania and New Jersey that provide electric transmission and distribution services. Its other material business segment consists of the subsidiaries that operate unregulated energy and energy-related businesses. The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. It also provides generation services to regulated franchise customers who have not chosen an alternative, competitive generation supplier. The regulated services segment obtains a portion of its required generation through power supply agreements with the competitive services segment. 21
<TABLE> <CAPTION> Segment Financial Information - ----------------------------- Regulated Competitive Reconciling Services Services Other Adjustments Consolidated -------- -------- ----- ----------- ------------ (In millions) <S> <C> <C> <C> <C> <C> Three Months Ended: - ------------------- September 30, 2003 ------------------ External revenues............................ $ 2,532 $ 889 $ 24 $ (2)(a) $ 3,443 Internal revenues............................ 296 578 135 (1,009)(b) -- Total revenues............................ 2,828 1,467 159 (1,011) 3,443 Depreciation and amortization................ 312 9 11 -- 332 Net interest charges......................... 117 12 54 18 (b) 201 Income taxes................................. 206 (38) (36) -- 132 Income before discontinued operations and cumulative effect of accounting change ..................... 284 (77) (54) -- 153 Net income (loss)............................ 284 (77) (54) -- 153 Total assets................................. 29,794 2,324 1,377 -- 33,495 Total goodwill............................... 5,993 135 -- -- 6,128 Property additions........................... 63 88 5 -- 156 September 30, 2002 (Restated - see Note 1) ------------------------------------------ External revenues............................ $ 2,718 $ 712 $ 19 $ 2 (a) $ 3,451 Internal revenues............................ 261 662 116 (1,039)(b) -- Total revenues............................ 2,979 1,374 135 (1,037) 3,451 Depreciation and amortization................ 294 8 8 -- 310 Net interest charges......................... 141 17 76 (14)(b) 220 Income taxes................................. 265 (10) (33) -- 222 Net income (loss)............................ 358 (15) (58) -- 285 Total assets................................. 30,776 2,174 2,077 -- 35,027 Total goodwill............................... 5,878 280 (4) -- 6,154 Property additions........................... 150 69 56 -- 275 Nine Months Ended: - ------------------ September 30, 2003 ------------------ External revenues............................ $ 6,931 $2,494 $ 86 $ 29 (a) $ 9,540 Internal revenues............................ 794 1,650 406 (2,850)(b) -- Total revenues............................ 7,725 4,144 492 (2,821) 9,540 Depreciation and amortization................ 909 25 32 -- 966 Net interest charges......................... 374 33 263 (57)(b) 613 Income taxes................................. 440 (99) (97) -- 244 Income before discontinued operations and cumulative effect of accounting change ... 607 (177) (158) -- 272 Net income (loss)............................ 708 (176) (219) -- 313 Total assets................................. 29,794 2,324 1,377 -- 33,495 Total goodwill............................... 5,993 135 -- -- 6,128 Property additions........................... 218 302 60 -- 580 September 30, 2002 (Restated - see Note 1) ------------------------------------------ External revenues............................ $ 6,982 $1,887 $ 320 $ 14 (a) $ 9,203 Internal revenues............................ 793 1,489 358 (2,640)(b) -- Total revenues............................ 7,775 3,376 678 (2,626) 9,203 Depreciation and amortization................ 867 21 32 -- 920 Net interest charges......................... 458 34 300 (43)(b) 749 Income taxes................................. 623 (47) (92) -- 484 Net income (loss)............................ 805 (68) (126) -- 611 Total assets................................. 30,776 2,174 2,077 -- 35,027 Total goodwill............................... 5,878 280 (4) -- 6,154 Property additions........................... 414 179 102 -- 695 <FN> Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting: (a) Principally fuel marketing revenues which are reflected as reductions to expenses for internal management reporting purposes. (b) Elimination of intersegment transactions. </FN> </TABLE> 22
<TABLE> <CAPTION> FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ------------------------ ----------------------- 2003 2002 2003 2002 ---------- ---------- ---------- ---------- Restated Restated (See Note 1) (See Note 1) (In thousands, except per share amounts) <S> <C> <C> <C> <C> REVENUES: Electric utilities..................................... $2,531,639 $2,717,461 $6,930,662 $6,981,753 Unregulated businesses................................. 911,746 733,723 2,609,625 2,221,282 ---------- ---------- ---------- ---------- Total revenues..................................... 3,443,385 3,451,184 9,540,287 9,203,035 ---------- ---------- ---------- ---------- EXPENSES: Fuel and purchased power............................... 1,324,297 1,274,679 3,642,936 2,705,007 Purchased gas.......................................... 103,000 95,799 456,823 447,980 Other operating expenses............................... 898,507 866,273 2,705,407 2,791,892 Provision for depreciation and amortization............ 332,125 310,417 966,009 920,196 Goodwill impairment (Note 1)........................... 121,523 -- 121,523 -- General taxes.......................................... 177,499 176,850 518,823 493,944 ---------- ---------- ---------- ---------- Total expenses..................................... 2,956,951 2,724,018 8,411,521 7,359,019 ---------- ---------- ---------- ---------- INCOME BEFORE INTEREST AND INCOME TAXES................... 486,434 727,166 1,128,766 1,844,016 ---------- ---------- ---------- ---------- NET INTEREST CHARGES: Interest expense....................................... 199,418 212,477 599,738 704,724 Capitalized interest................................... (6,513) (6,303) (23,287) (18,722) Subsidiaries' preferred stock dividends................ 8,021 14,223 36,423 63,399 ---------- ---------- ---------- ---------- Net interest charges............................... 200,926 220,397 612,874 749,401 ---------- ---------- ---------- ---------- INCOME TAXES.............................................. 132,789 221,924 244,211 483,604 ---------- ---------- ---------- ---------- INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE................. 152,719 284,845 271,681 611,011 Discontinued operations (net of income taxes of $3,700,000) (Note 3)................................. -- -- (60,495) -- Cumulative effect of accounting change (net of income taxes of $72,516,000) (Note 5)....................... -- -- 102,147 -- ---------- ---------- ---------- ---------- NET INCOME................................................ $ 152,719 $ 284,845 $ 313,333 $ 611,011 ========== ========== ========== ========== BASIC EARNINGS PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change.......................... $ .51 $ .97 $ .92 $ 2.08 Discontinued operations (net of income taxes) (Note 3). -- -- (.21) -- Cumulative effect of accounting change (net of income taxes)(Note 5)....................................... -- -- .35 -- ----- ----- ------ ------ Net income......................................... $ .51 $ .97 $ 1.06 $ 2.08 ===== ===== ====== ====== WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING............................................ 299,422 293,328 295,825 293,066 ======= ======= ======= ======= DILUTED EARNINGS PER SHARE OF COMMON STOCK: Income before discontinued operations and cumulative effect of accounting change.......................... $ .51 $ .97 $ .91 $ 2.08 Discontinued operations (net of income taxes) (Note 3). -- -- (.21) -- Cumulative effect of accounting change (net of income taxes)(Note 5)....................................... -- -- .35 -- ----- ----- ------ ------ Net income......................................... $ .51 $ .97 $ 1.05 $ 2.08 ===== ===== ====== ====== WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING............................................ 300,751 294,277 297,153 294,385 ======= ======= ======= ======= DIVIDENDS DECLARED PER SHARE OF COMMON STOCK.............. $.375 $.375 $1.125 $1.125 ===== ===== ====== ====== <FN> The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. </FN> </TABLE> 23
<TABLE> <CAPTION> FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (See Note 1) (In thousands) <S> <C> <C> ASSETS ------ CURRENT ASSETS: Cash and cash equivalents................................................. $ 178,911 $ 196,301 Receivables- Customers (less accumulated provisions of $57,509,000 and $52,514,000 respectively, for uncollectible accounts)............................. 1,126,111 1,153,486 Other (less accumulated provisions of $7,651,000 and $12,851,000, respectively, for uncollectible accounts)............................. 406,995 469,606 Materials and supplies, at average cost- Owned................................................................... 282,403 253,047 Under consignment....................................................... 158,506 174,028 Prepayments and other..................................................... 203,078 203,630 ----------- ----------- 2,356,004 2,450,098 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT: In service................................................................ 21,497,981 20,372,224 Less--Accumulated provision for depreciation.............................. 9,286,506 8,552,927 ----------- ----------- 12,211,475 11,819,297 Construction work in progress............................................. 699,180 859,016 ----------- ----------- 12,910,655 12,678,313 ----------- ----------- INVESTMENTS: Capital trust investments................................................. 993,688 1,079,435 Nuclear plant decommissioning trusts...................................... 1,230,356 1,049,560 Letter of credit collateralization........................................ 277,763 277,763 Other..................................................................... 939,974 918,874 ----------- ----------- 3,441,781 3,325,632 ----------- ----------- DEFERRED CHARGES: Regulatory assets......................................................... 7,798,768 8,753,401 Goodwill.................................................................. 6,127,853 6,278,072 Other..................................................................... 859,930 900,837 ----------- ----------- 14,786,551 15,932,310 ----------- ----------- $33,494,991 $34,386,353 =========== =========== </TABLE> 24
<TABLE> <CAPTION> FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (See Note 1) (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ <S> <C> <C> CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... $ 1,576,882 $ 1,702,822 Short-term borrowings..................................................... 246,084 1,092,817 Accounts payable.......................................................... 722,156 906,468 Accrued taxes............................................................. 667,938 455,121 Lease market valuation liability.......................................... 84,600 84,600 Other..................................................................... 834,454 1,009,215 ----------- ----------- 4,132,114 5,251,043 ----------- ----------- CAPITALIZATION: Common stockholders' equity- Common stock, $.10 par value, authorized 375,000,000 shares - 329,836,276 and 297,636,276, shares outstanding, respectively......... 32,984 29,764 Other paid-in capital................................................... 7,055,651 6,120,341 Accumulated other comprehensive loss.................................... (532,560) (656,148) Retained earnings....................................................... 1,617,499 1,634,981 Unallocated employee stock ownership plan common stock - 3,106,709 and 3,966,269 shares, respectively.......................... (62,142) (78,277) ----------- ----------- Total common stockholders' equity................................... 8,111,432 7,050,661 Preferred stock of consolidated subsidiaries- Not subject to mandatory redemption..................................... 335,123 335,123 Subject to mandatory redemption (Note 5)................................ -- 18,521 Subsidiary-obligated mandatorily redeemable preferred securities (Note 5)..... .......................................................... -- 409,867 Long-term debt and other long-term obligations- Preferred stock of consolidated subsidiaries subject to mandatory redemption (Note 5) .................................................. 17,516 -- Subsidiary-obligated mandatorily redeemable preferred securities (Note 5)... .......................................................... 284,940 -- Other................................................................... 10,396,512 10,872,216 ----------- ----------- 19,145,523 18,686,388 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 1,986,721 2,069,682 Accumulated deferred investment tax credits............................... 217,934 236,184 Asset retirement obligations.............................................. 1,161,145 -- Nuclear plant decommissioning costs....................................... -- 1,243,558 Power purchase contract loss liability.................................... 2,905,347 3,136,538 Retirement benefits....................................................... 1,806,632 1,564,930 Lease market valuation liability.......................................... 1,042,450 1,106,000 Other..................................................................... 1,097,125 1,092,030 ----------- ----------- 10,217,354 10,448,922 ----------- ----------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ----------- ----------- $33,494,991 $34,386,353 =========== =========== <FN> The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these balance sheets. </FN> </TABLE> 25
<TABLE> <CAPTION> FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ------------------------ ------------------------- 2003 2002 2003 2002 ---------- ---------- ----------- ----------- Restated Restated (See Note 1) (See Note 1) (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 152,719 $ 284,845 $ 313,333 $ 611,011 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 332,125 310,417 966,009 920,196 Nuclear fuel and capital lease amortization........ 16,902 20,191 47,398 60,754 Deferred costs recoverable as regulatory assets.... (32,650) (145,336) (142,340) (291,406) Goodwill impairment................................ 121,523 -- 121,523 -- Deferred operating lease costs, net................ (6,401) 10,443 (86,363) (88,049) Deferred income taxes, net......................... (42,433) 34,491 (63,987) 33,391 Amortization of investment tax credits............. (7,349) (6,767) (19,855) (20,480) Accrued retirement benefit obligations............. 81,819 24,941 229,172 54,216 Accrued compensation, net.......................... (1,812) (14,070) (50,246) (87,943) Revenue credits to customers....................... (19,583) (17,434) (71,984) (17,434) Disallowed purchased power costs................... -- -- 152,500 -- Discontinued operations............................ -- -- 60,495 -- Cumulative effect of accounting change............. -- -- (174,663) -- Other amortization and accruals, net............... (9,540) (3,937) (6,244) (12,104) Tax refund related to pre-merger period............ -- -- 51,073 -- Energy derivative transactions, net................ (34,939) (19,105) (31,137) (4,136) Receivables........................................ 104,516 (61,113) 43,959 (157,670) Materials and supplies............................. 19,708 (18,388) (14,276) (21,967) Accounts payable................................... (136,271) 40,900 (171,314) 92,650 Accrued taxes...................................... 188,261 16,687 210,115 103,407 Accrued interest................................... 68,669 79,063 52,991 59,507 Prepayments and other current assets............... 109,687 113,841 (10,871) 94,455 Other.............................................. (9,224) 18,748 (25,568) 66,226 ---------- ---------- ----------- ----------- Net cash provided from operating activities...... 895,727 668,417 1,379,720 1,394,624 ---------- ---------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Common stock......................................... 934,605 -- 934,605 -- Long-term debt....................................... -- 317,890 981,637 684,620 Short-term borrowings, net........................... -- 508,720 -- 539,271 Redemptions and Repayments- Preferred stock...................................... (1,000) (313,517) (126,337) (503,816) Long-term debt....................................... (569,273) (871,608) (1,547,205) (1,250,251) Short-term borrowings, net........................... (798,985) -- (846,734) -- Common stock dividend payments......................... (110,373) (109,963) (330,816) (329,565) ---------- ---------- ----------- ----------- Net cash used for financing activities........... (545,026) (468,478) (934,850) (859,741) ---------- ---------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... (155,908) (274,923) (580,069) (694,614) Proceeds from sale of assets........................... 1,081 -- 67,530 155,034 Proceeds from note receivable.......................... -- -- 19,000 -- Avon cash and cash equivalents (Note 3)................ -- -- -- 31,326 Proceeds from nonutility generation trusts............. -- -- 106,327 34,208 Cash investments....................................... 31,696 (4,310) 46,761 59,712 Contributions to nuclear decommissioning trusts........ (47,622) (24,951) (75,873) (78,099) Debt remarketing investments .......................... (73,231) -- (73,231) -- Other.................................................. 7,990 25,742 27,295 17,919 ---------- ----------- ----------- ----------- Net cash used for investing activities........... (235,994) (278,442) (462,260) (474,514) ---------- ---------- ----------- ----------- Net increase (decrease) in cash and cash equivalents...... 114,707 (78,503) (17,390) 60,369 Cash and cash equivalents at beginning of period.......... 64,204 359,050 196,301 220,178 ---------- ---------- ----------- ----------- Cash and cash equivalents at end of period................ $ 178,911 $ 280,547 $ 178,911 $ 280,547 ========== ========== =========== =========== <FN> The preceding Notes to Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. </FN> </TABLE> 26
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 September 30, 2003, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for each of the three-month and nine-month periods ended September 30, 2002. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholders' equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for goodwill in 2002 as discussed in Note 2(E) to those consolidated financial statements and the Company's restatement of its previously issued consolidated financial statements for the year ended December 31, 2002 as discussed in Note 2(L) and Note 2(M) to those consolidated financial statements) dated February 28, 2003, except as to Note 2(L), which is as of May 9, 2003, and Notes 2(M) and 8, which are as of August 18, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2003 27
FIRSTENERGY CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FirstEnergy Corp. is a registered public utility holding company that provides regulated and competitive energy services (see Results of Operations - Business Segments). International assets were acquired as part of FirstEnergy's acquisition of GPU, Inc. in November 2001. GPU Capital, Inc. and its subsidiaries provided electric distribution services in foreign countries (see Results of Operations - Discontinued Operations). GPU Power, Inc. and its subsidiaries develop, own and operate generation facilities in foreign countries. Sales are planned but not pending for the remaining international assets (see Capital Resources and Liquidity). Regulated electric distribution services are provided in Ohio by wholly owned subsidiaries (Ohio electric utilities) - Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), and The Toledo Edison Company (TE). Regulated services are provided in Pennsylvania through wholly owned subsidiaries (Pennsylvania electric utilities) - Metropolitan Edison Company (Met-Ed), Pennsylvania Electric Company (Penelec) and Pennsylvania Power Company (Penn) - a wholly owned subsidiary of OE. Jersey Central Power & Light Company (JCP&L) provides electric distribution services in New Jersey. Transmission services are provided in the franchise areas of the Ohio electric utilities and Penn by wholly owned subsidiary American Transmission Systems, Inc. Transmission services are provided by Met-Ed, Penelec and JCP&L in their respective franchise areas. The coordinated delivery of energy and energy-related products, including electricity, natural gas and energy management services, to customers in competitive markets is provided through a number of subsidiaries. Subsidiaries providing competitive services include FirstEnergy Solutions Corp. (FES), FirstEnergy Facilities Services Group, LLC (FSG), MARBEL Energy Corporation and MYR Group, Inc (MYR). RESTATEMENTS AND RECLASSIFICATIONS As further discussed in Note 1 to the Consolidated Financial Statements, FirstEnergy restated its consolidated financial statements for the year ended December 31, 2002 and the three months ended March 31, 2003 to reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. These restatements were completed and reported in the second quarter of 2003 together with reclassifications discussed in Note 3 to the Consolidated Financial Statements. Financial comparisons described below for the three-month and nine-month periods reflect the effect of these restatements and reclassifications of 2002 financial results. RESULTS OF OPERATIONS FirstEnergy reported net income in the third quarter of 2003 of $152.7 million, or $0.51 per share of common stock (basic and diluted), compared to net income of $284.8 million, or $0.97 per share of common stock (basic and diluted) in the third quarter of 2002. During the first nine months of 2003, net income was $313.3 million, or basic earnings of $1.06 per share of common stock ($1.05 diluted), compared to net income of $611.0 million, or $2.08 per share of common stock (basic and diluted) in the first nine months of 2002. Income before discontinued operations and the cumulative effect of an accounting change was $152.7 million, or $0.51 per share of common stock (basic and diluted) in the third quarter of 2003 and $271.7 million, or basic earnings of $0.92 per share of common stock ($0.91 diluted) in the first nine months of 2003. Results for the third quarter and nine-month period in 2003 included an after-tax goodwill impairment of $80.9 million, or $0.27 per share of common stock (basic and diluted) for both periods. Net income for the first nine months of 2003 also included a $60.5 million after-tax charge for discontinued operations in Argentina and an after-tax credit of $102.1 million resulting from the cumulative effect of an accounting change due to the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." Results for the third quarter of 2003 compared to the third quarter of 2002 were adversely affected by milder weather which reduced revenues. Purchased power costs, storm damage, employee benefit expenses and nuclear refueling costs all contributed to increased third quarter expenses, compared to the same quarter last year. In addition, FirstEnergy recorded a non-cash charge of $121.5 million ($80.9 million, net of tax) for goodwill impairment in the third quarter of 2003. In the first nine months of 2003, expenses increased compared to the same period of 2002 due to: purchased power costs, nuclear expenses related to the extended outage at the Davis-Besse Nuclear Power Station (see Outlook-Davis-Besse Restoration), additional unplanned work performed during two scheduled nuclear refueling outages in the second quarter of 2003 and increased employee benefit expenses. However, the absence in the first nine months of 2003 of unusual charges incurred in the corresponding period of 2002 partially offset the cost increases in 2003. The 2003 year-to-date period included $171.6 million of pre-tax charges for costs disallowed in the JCP&L rate case decision (see State Regulatory Matters - New Jersey). 28
Revenues Total revenues decreased $7.8 million in the third quarter of 2003, compared to the same period last year, due to lower retail and wholesale regulated electric sales. Increased revenues from competitive services, primarily electric sales to wholesale customers, partially offset the decrease in regulated electric retail revenues in the third quarter of 2003. In the first nine months of 2003, revenues increased $337.3 million compared to the same period of 2002 from increased competitive sales, offset in part by reduced regulated revenues and lower international sales reflecting the partial sale of Avon Energy Partners Holdings. Sources of changes in revenues during the third quarter and first nine months of 2003 compared to the corresponding periods of 2002 are summarized in the following table: Sources of Revenue Changes Three Months Nine Months --------------------------------------------------------------------------- Increase (Decrease) (In millions) Electric Utilities (Regulated Services): Retail electric sales................. $(118.9) $(161.9) Wholesale electric sales ............. (75.8) 105.1 All other revenues.................... 8.9 5.7 ----------------------------------------------------------------------- Total Electric Utilities................. (185.8) (51.1) ----------------------------------------------------------------------- Unregulated Businesses (Competitive Services): Retail electric sales................. 62.4 177.4 Wholesale electric sales.............. 184.5 612.0 Gas sales............................. 9.7 21.5 FSG................................... (57.4) (151.3) MYR................................... (20.1) (73.3) Other................................. (2.7) 21.1 ----------------------------------------------------------------------- Total Unregulated Businesses............. 176.4 607.4 ----------------------------------------------------------------------- International............................ 2.3 (241.1) Other.................................... (0.7) 22.1 ----------------------------------------------------------------------- Net Change in Revenue.................... $ (7.8) $ 337.3 ======================================================================= Electric Sales Retail sales by FirstEnergy's electric utility operating companies (EUOC) decreased by $118.9 million in the third quarter of 2003 and by $161.9 million in the first nine months of 2003 from the corresponding periods of 2002. Changes in electric generation kilowatt-hour sales and distribution deliveries in the third quarter and first nine months of 2003 from the same periods of 2002 are summarized in the following table: Changes in Kilowatt-hour Sales Three Months Nine Months - ----------------------------------------------------------------------- Increase (Decrease) Electric Generation Sales: Retail - Regulated services................. (11.4)% (6.9)% Competitive services............... 37.6% 66.0% Wholesale............................ 17.9% 71.2% - -------------------------------------------------------------------- Total Electric Generation Sales........ 0.5% 14.0% ==================================================================== EUOC Distribution Deliveries: Residential.......................... (7.1)% 0.6% Commercial........................... (4.1)% 1.9% Industrial........................... (2.7)% (1.4)% - --------------------------------------------------------------------- Total Distribution Deliveries.......... (4.7)% 0.3% ==================================================================== Reduced air-conditioning load due to cooler summer temperatures in 2003 from the prior year, a sluggish but improving economy and increased sales by alternative suppliers all combined to decrease regulated retail generation sales revenue by $55.5 million in the third quarter of 2003 compared to the same quarter of 2002. These factors also accounted for most of the $168.2 million decrease in retail generation sales revenue in the first nine months of 2003 compared to the same period last year. Kilowatt-hour sales of electricity by alternative suppliers in FirstEnergy's franchise areas increased by approximately six percentage points in the three months and nine months ended September 30, 2003, from the corresponding periods last year. 29
Revenues from distribution deliveries decreased by $56.5 million or 3.8% in the third quarter of 2003 compared to the third quarter of 2002 due in part to mild weather in the third quarter of 2003 after unusually hot weather in the same period last year which reduced the air-conditioning load of residential and commercial customers. Weather also contributed to the $38.0 million, or 1.0% increase in distribution deliveries to residential and commercial customers in the first nine months of 2003 from the same period last year due to colder temperatures in the first three months of 2003 from same period last year, adding to heating-related loads. Sluggish economic conditions in the third quarter and first nine months of 2003 contributed to reduced distribution deliveries to industrial customers from the corresponding periods last year. Further contributing to the decrease in retail electric revenues were Ohio transition plan incentives provided to customers to promote customer shopping for alternative suppliers - $6.9 million of additional credits in the third quarter and $31.7 million of additional credits in the first nine months of 2003 compared to the same periods in 2002. These additional credits in revenue are deferred for future recovery under the Ohio transition plan and do not materially affect current period earnings. EUOC sales to wholesale customers decreased by $75.8 million in the third quarter of 2003 from the same period last year due to milder summer weather in 2003. Sales to the wholesale market increased $105.1 million in the first nine months of 2003 compared to the first nine months of 2002 primarily due to the auction of JCP&L's basic generation service (BGS) responsibility to alternative suppliers. At the direction of the New Jersey Board of Public Utilities (NJBPU), JCP&L is selling power under contracts existing as of August 2002, including energy provided by non-utility generation (NUG) contracts, into the wholesale market. Electric generation sales by FirstEnergy's competitive segment increased $246.9 million in the third quarter and $789.4 million in the first nine months of 2003 from the corresponding periods of 2002, primarily from additional sales to the wholesale market ($184.5 million in the third quarter and $612.0 million in the first nine months of 2003). The increases resulted in part from sales in New Jersey as FES began supplying a portion of that state's BGS in September 2002. Retail sales by FirstEnergy's competitive services segment increased by $62.4 million in the third quarter and $177.4 million in the first nine months of 2003 from the same periods of 2002. The increases primarily resulted from retail customers within FirstEnergy's Ohio franchise areas switching to FES under Ohio's electricity choice program and from growth in competitive retail sales outside FirstEnergy's franchise areas. FirstEnergy's regulated and unregulated subsidiaries record purchase and sale transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." This gross basis classification of revenues and costs may not be comparable to other energy companies that operate in regions that have not established ISOs and do not meet EITF 99-19 criteria. The aggregate purchase and sales transactions for the three and nine months ended September 30, 2003 and 2002 are summarized as follows: Three Months Ended Nine Months Ended September 30, September 30, ---------------------------------------------- 2003 2002 2003 2002 - ------------------------------------------------------------------- (In millions) Sales.............. $465 $189 $1,009 $256 Purchases.......... 288 382 866 579 - ------------------------------------------------------------------ FirstEnergy's revenues on its Consolidated Statements of Income include wholesale electricity sales revenues from the PJM ISO from power sales (as reflected in the table above) during periods when it had additional available power capacity. Revenues also include sales by FirstEnergy of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when it required additional power to meet FirstEnergy's retail load requirements and, secondarily, to sell in the wholesale market. Nonelectric Sales Nonelectric sales revenues of the competitive services segment declined by $70.5 million in the third quarter and $182.0 million in the first nine months of 2003 from the corresponding periods of 2002. The reduced revenues from FSG reflected the divestiture in early 2003 of its Colonial Mechanical and Webb Technologies subsidiaries (accounting for the majority of the decreases), as well as declines associated with weak economic conditions. MYR also experienced revenue reductions resulting from the sluggish economic environment. Natural gas sales were $9.7 million and $21.5 million higher in the third quarter and year-to-date periods compared to the corresponding periods last year. The increase in gas sales in the third quarter and first nine month of 2003 reflected increased prices which more than offset lower gas volumes delivered as FES focused its operations in a narrower geographic area and on higher-margin gas customers. 30
International Revenues International revenues declined $241.1 million in the first nine months of 2003 from the same period last year due to the sale of a 79.9% interest in Avon during the second quarter of 2002 and abandonment of Emdersa in the second quarter of 2003 (see Discontinued Operations below). As a result of these transactions, FirstEnergy has substantially divested all of GPU Capital's international operations acquired in the 2001 GPU merger. Expenses Total expenses increased $232.9 million in the third quarter and $1,052.5 million in the first nine months of 2003 from the same periods of 2002. Sources of changes in expenses in the third quarter and first nine months of 2003 compared to the corresponding periods of 2002 are summarized in the following table: Sources of Expense Changes Three Months Nine Months - ---------------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel and purchased power.............. $ 49.6 $ 937.9 Purchased gas......................... 7.2 8.9 Other operating expenses.............. 32.2 (86.5) Depreciation and amortization......... 21.7 45.8 Goodwill Impairment................... 121.5 121.5 General taxes......................... 0.7 24.9 - -------------------------------------------------------------------------- Net Increase in Expenses................ $232.9 $1,052.5 ========================================================================== Higher purchased power costs accounted for $58.2 of the increase in expenses in the third quarter of 2003 and most of the increase ($968.6 million) in the first nine months of 2003 compared to the same periods of 2002. Higher unit costs contributed to increased purchased power costs in the third quarter and first nine months of 2003 from the corresponding periods last year. Additional quantities purchased also contributed significantly to the increased purchase power costs in the first nine months of 2003 from the prior year. Increased volumes were required to supply obligations assumed by FES for BGS sales, as well as other wholesale commitments, and additional supplies required to replace reduced nuclear generation. Results for the nine-month period include $152.5 million of purchased power costs disallowed in the JCP&L rate case decision (see State Regulatory Matters - New Jersey). The combined effect of one additional refueling outage in 2003 compared to 2002, additional work performed in 2003 during the refueling outages at the Perry Plant and Beaver Valley Unit 1 and the extended Davis-Besse outage, reduced nuclear generation by 5.7% in the third quarter and 18.4% in the first nine months of 2003 from the corresponding periods last year. Fuel expenses were $8.6 million and $30.7 million lower in the third quarter and first nine months of 2003, respectively, from the same periods of 2002, primarily reflecting reduced generation. Purchased gas costs increased by $7.2 million in the third quarter and $8.9 million in the first nine months of 2003 compared to the same periods of 2002 due to higher unit costs, partially offset by lower volumes purchased to meet reduced gas deliveries. Other operating expenses increased $32.2 million in the third quarter of 2003, compared to the same period of 2002, due to higher energy delivery costs of $52.5 million (primarily due to storm restoration expenses and an accelerated reliability plan within JCP&L's service territory), increased pension and benefit costs (see Employee Benefit Plan Costs below) and additional nuclear operating costs ($27.2 million) associated with a refueling outage at Beaver Valley Unit 2 - completed on October 12, 2003. There were no nuclear refueling outages in the third quarter of 2002. Partially offsetting these increases were reduced costs from domestic energy-related businesses ($69.1 million) and reduced costs at the Davis-Besse nuclear plant related to its extended outage as the plant approaches a return to operation (see Outlook-Davis-Besse Restoration below). The reduced volume of energy-related business reflects the sale in early 2003 of Colonial Mechanical and Webb Technologies businesses and lower business volumes associated with weak economic conditions. In the first nine months of 2003, other operating expenses decreased $86.5 million from the same period last year as a result of several factors. Reduced business volumes and the sale of Colonial and Webb reduced expenses from domestic energy-related businesses by $212.0 million, while the sale of Avon and divestiture of Emdersa resulted in a $95.3 million reduction in expense from international operations. The absence of unusual charges recognized in the first nine months of 2002 resulted in a further net reduction of other operating expenses ($70.7 million) from the corresponding period last year. Offsetting a portion of these lower expenses in the first nine months of 2003 were increased nuclear costs ($93.0 million) resulting from the extended Davis-Besse outage, additional work performed during refueling outages in the second quarter of 2003 and three refueling outages in the first nine months of 2003 versus two in 2002. Administrative and general costs increased $172.6 million principally reflecting increased employee benefit costs. Energy delivery costs increased $51.5 million primarily as a result of storm damage and an accelerated reliability plan within JCP&L's service territory. 31
Charges for depreciation and amortization increased by $21.7 million in the third quarter of 2003 compared to the corresponding three-month period of 2002. The higher charges primarily resulted from three factors - increased amortization of the Ohio transition regulatory assets ($22.7 million), recognition of depreciation on four power plants ($11.7 million) which had been held pending sale in the third quarter of 2002, but were subsequently retained by FirstEnergy in the fourth quarter of 2002, and reduced regulatory asset deferrals in 2003 ($12.2 million). Partially offsetting these increases in depreciation and amortization were higher shopping incentive deferrals in Ohio ($6.9 million), lower charges resulting from the implementation of SFAS 143 ($12.7 million) and revised service life assumptions for generating plants ($7.4 million). In the first nine months of 2003, depreciation and amortization increased $45.8 million primarily as a result of the same factors which influenced the third quarter comparison - increased amortization of the Ohio transition regulatory assets ($64.8 million), recognition of depreciation on four power plants ($31.2 million) previously held pending sale in the first nine months of 2002, reduced regulatory asset deferrals in 2003 ($27.2 million) and costs of $19.1 million disallowed in the JCP&L rate case decision. Partially offsetting these increases in depreciation and amortization were higher shopping incentive deferrals in Ohio ($31.7 million), lower charges resulting from the implementation of SFAS 143 ($41.1 million) and revised service life assumptions for generating plants ($20.0 million). A non-cash goodwill impairment charge of $121.5 million ($80.9 million, net of tax) was recognized in the third quarter of 2003 reducing the carrying value of FSG. This charge reflects the continued slow down in the development of competitive retail markets and depressed economic conditions that affect the value of FSG. General taxes increased $24.9 million in the first nine months of 2003 compared to the same period last year. Higher payroll and kilowatt-hour taxes in 2003 and a $9 million energy assessment credit adjustment that reduced general taxes in the first nine months of 2002 were the principal factors contributing to the increase. Net Interest Charges Net interest charges decreased $19.5 million in the third quarter and $136.5 million in the first nine months of 2003 compared to the same periods of 2002, due to previous debt and preferred stock redemptions and refinancing activities and the sale of a 79.9% interest in Avon in 2002. Redemption and refinancing activities during the first nine months of 2003 totaled $656 million and $850 million (including $227 million of pollution control note repricings), respectively, and are expected to result in annualized interest charge savings of approximately $68 million. Partially offsetting these savings are interest charges on additional borrowings under revolving bank credit facilities. FirstEnergy also exchanged existing fixed-rate interest payments on outstanding debt (principal amount of $600 million as of September 30, 2003) for short-term variable rate interest payments through interest rate swap transactions (see Market Risk Information - Interest Rate Swap Agreements below). Net interest charges were reduced by $5.2 million in the third quarter and $19.8 million in the first nine months of 2003, compared to the corresponding periods of 2002 as a result of the lower variable rates paid under these agreements. Discontinued Operations On April 18, 2003, FirstEnergy divested its ownership in Emdersa. The abandonment was accomplished by relinquishing FirstEnergy's shares of Emdersa's parent company, GPU Argentina Holdings, to that company's independent Board of Directors, relieving FirstEnergy of all rights and obligations relative to this business. As a result of this action, FirstEnergy's gains and losses related to discontinuing these operations have been presented as a separate item on the Consolidated Statements of Income - "Discontinued operations" - in accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Due to the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67.4 million in the second quarter of 2003. This charge resulted from realizing $89.8 million of currency translation losses through current period earnings, partially offset by a $22.4 million gain recognized from eliminating FirstEnergy's investment in Emdersa. Discontinued operations for the nine-month period reflected a net after-tax charge of $60.5 million, which included $6.9 million of earnings from Emdersa in the first quarter of 2003. As a result of the abandonment, FirstEnergy has substantially divested all of GPU Capital's international operations acquired in the 2001 GPU merger. Cumulative Effect of Accounting Change Results for the first nine months of 2003 include an after-tax credit to net income of $102.1 million recorded upon the adoption of SFAS 143 in January 2003 (see discussion below). FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant and two coal ash disposal sites. 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 asset retirement obligation (ARO) liability at the date of adoption was $1.107 billion, including accumulated accretion for the period from the date the liability was incurred to the date of 32
adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.244 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 was a $174.7 million increase to income, or $102.1 million net of income taxes. Earnings Effect of SFAS 143 In June 2001, the FASB issued SFAS 143. That statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. In the third quarter and first nine months of 2003, application of SFAS 143 (excluding the cumulative adjustment recorded upon adoption - see Note 5) resulted in the following changes to income and expense categories: <TABLE> <CAPTION> Ended September 30, 2003 - ------------------------------------------------------------------------------------- Effect of SFAS 143 Three Months Nine Months - ------------------------------------------------------------------------------------- Increase (Decrease) (In millions) Other operating expense - ----------------------- <S> <C> <C> Cost of removal (previously included in depreciation)... $ 0.1 $ 4.4 Depreciation - ------------ Elimination of decommissioning expense.................. (22.3) (67.0) Depreciation of asset retirement cost................... 0.4 1.5 Accretion of asset retirement liability................. 10.5 30.9 Reclassification of cost of removal to expense ......... (1.3) (6.5) - ----------------------------------------------------------------------------------- Net decrease to depreciation............................ (12.7) (41.1) - ----------------------------------------------------------------------------------- Other Income - ------------ Earnings on decommissioning trust balances.............. 7.3 10.5 - ---------------------------------------------------------------------------------- Income taxes............................................ 8.2 19.4 - ---------------------------------------------------------------------------------- Net income effect....................................... $ 11.7 $ 27.8 ================================================================================== </TABLE> Employee Benefit Plan Costs Sharp declines in equity markets since the second quarter of 2000 and a reduction in FirstEnergy's assumed discount rate for pensions and other post-employment benefit (OPEB) obligations have combined to produce a significant increase in those costs. Also, increases in health care payments and a related increase in projected trend rates have led to higher health care costs. Combined, these employee benefit expenses increased by $45.4 million in the third quarter and $139.1 million in the first nine months of 2003 compared to the same periods in 2002. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized) for the three months and nine months ended September 30, 2003 and 2002. <TABLE> <CAPTION> Three Months Ended Nine Months Ended Pension and OPEB Expense (Income) September 30, September 30, - -------------------------------------------------------------------------------------- 2003 2002 2003 2002 ---------------------------------------------- (In millions) <S> <C> <C> <C> <C> Pension............................ $32.7 $ (6.0) $ 91.3 $(10.5) OPEB............................... 39.3 32.6 118.3 81.0 - -------------------------------------------------------------------------------------- Total........................ $72.0 $26.6 $209.6 $ 70.5 ====================================================================================== </TABLE> The pension and OPEB expense increases are included in various cost categories and have contributed to other cost increases discussed above. See "Significant Accounting Policies - Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement expenses. 33
RESULTS OF OPERATIONS - BUSINESS SEGMENTS FirstEnergy manages its business as two separate major business segments - regulated services and competitive services. The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated domestic transmission and distribution systems. It also provides generation services to franchise customers who have not chosen an alternative generation supplier. The Ohio electric utilities and Penn obtain generation through a power supply agreement with the competitive services segment (see Outlook - Business Organization). The competitive services segment also supplies a substantial portion of the "provider of last resort" (PLR) requirements for Met-Ed and Penelec through a wholesale contract. The competitive services segment includes all competitive energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation, trading and sourcing of commodity requirements, as well as other competitive energy services such as heating, ventilation and air-conditioning. Financial results discussed below include intersegment revenues. A reconciliation of segment financial results to consolidated financial results is provided in Note 7 to the consolidated financial statements. Regulated Services Net income decreased to $283.5 million in the third quarter of 2003, compared to $357.5 million in the third quarter of 2002. In the first nine months of 2003, net income decreased to $707.7 million from $804.7 million in the first nine months of 2002. The factors contributing to the changes in net income are summarized in the following table: Regulated Services Three Months Nine Months - -------------------------------------------------------------------------------- Increase (Decrease) (In millions) Revenues........................................ $(151.1) $ (50.1) Expenses........................................ 6.9 415.2 - ------------------------------------------------------------------------------ Income Before Interest and Income Taxes......... (158.0) (465.3) Net interest charges............................ (24.0) (83.5) Income taxes.................................... (60.0) (183.8) - ------------------------------------------------------------------------------- Decrease in Income Before Cumulative Effect of a Change in Accounting....................... (74.0) (198.0) Cumulative effect of a change in accounting..... -- 101.0 - ------------------------------------------------------------------------------ Net Income Decrease............................. $ (74.0) $ (97.0) ============================================================================== Lower generation sales and distribution deliveries combined to decrease external electric revenues by $192.7 million in the third quarter of 2003 compared to the same quarter of 2002. Cooler summer temperatures than the prior year and a continued sluggish economy contributed to reduced sales in the third quarter. Retail generation sales were also adversely affected by additional kilowatt-hour sales by alternative suppliers in the FirstEnergy franchise area. This decrease was partially offset by a $34.7 million increase in revenues from sales to FES. The remaining offset to lower revenues resulted from an increase in energy-related revenues. Revenues in the first nine months of 2003 decreased $50.1 million from the same period last year due to lower retail sales revenue partially offset by increased sales to wholesale customers. The decrease in retail revenues resulted from additional kilowatt-hour sales by alternative suppliers, the cooler summer temperatures and sluggish economy noted above but offset in part by colder-than-normal first quarter weather. Expenses increased in the third quarter and first nine months of 2003 from the corresponding periods of 2002. The increase in expenses in the third quarter of 2003 resulted principally from a $58.5 million increase in other operating costs primarily due to increased energy delivery costs and employee benefit costs and a $17.2 million increase in depreciation and amortization expenses. Offsetting factors included reduced purchased power costs of $57.2 million and lower general taxes of $9.7 million. In the first nine months of 2003, expenses increased $415.2 million from the same period of 2002. The increase in expenses resulted principally from a $287.2 million increase in purchased power costs due in large part to higher sales to wholesale customers. Purchased power costs in 2003 were further increased by a $152.5 million charge in the second quarter resulting from the JCP&L rate case. The other expense factors in the first nine months of 2003 compared to the first nine months of 2002 include a $90.8 million increase in other operating expense and a $41.9 million increase in depreciation and amortization expense. Other operating expenses increased in part due to storm damage and additional employee benefit costs from the corresponding period of 2002. Depreciation and amortization expenses increased from the same periods last year due principally to three factors - increased amortization of the Ohio transition regulatory assets, recognition of depreciation on four power plants which had been pending sale in the third quarter of 2002, but were subsequently retained by FirstEnergy in the fourth quarter of 2002, and the termination of regulatory asset deferrals in February 2003. A write-off of disallowed costs in the JCP&L rate case also contributed to the increase in the year-to-date period. Partially offsetting these increases in depreciation and 34
amortization were higher shopping incentive deferrals in Ohio and lower charges resulting from the implementation of SFAS 143, including revised service life assumptions for generating plants. Competitive Services Net losses increased to $77.0 million in the third quarter of 2003 from a net loss of $14.1 million in the third quarter of 2002. Net losses increased to $175.7 million in the first nine months of 2003 from a net loss of $67.3 million in the first nine months of last year. A non-cash impairment charge in the third quarter of 2003, discussed below, accounted for all of the net loss in that period and a majority of the loss in the first nine months of 2003. Factors contributing to the changes in earnings are summarized in the following table: Competitive Services Three Months Nine Months - --------------------------------------------------------------------------- Increase (Decrease) (In millions) Revenues.................................... $ 93.6 $ 768.3 Expenses.................................... 188.9 930.4 ----------------------------------------------------------------------- Income Before Interest and Income Taxes..... (95.3) (162.1) ------------------------------------------------------------------------ Net interest charges........................ (5.2) (1.2) Income taxes................................ (27.2) (51.3) ------------------------------------------------------------------------ Decrease in Income Before Cumulative Effect of a Change in Accounting.................. (62.9) (109.6) Cumulative effect of a change in accounting. -- 1.2 ----------------------------------------------------------------------- Net income change........................... $(62.9) $(108.4) ======================================================================== The increase in revenues in the third quarter and first nine months of 2003, compared to the corresponding periods of 2002, includes the net effect of several factors. Revenues from the electric wholesale market increased $184.5 million in the third quarter and $612.0 million in the first nine months of 2003 from the same periods last year. The large increase in year-to-date sales to the wholesale market reflects in large part sales as an alternative supplier for a portion of New Jersey's BGS requirements and sales to Met-Ed and Penelec in supplying a substantial portion of their PLR requirements in Pennsylvania. Retail kilowatt-hour sales revenues increased $62.4 million in the third quarter and $177.4 million in the first nine months of 2003 from the same periods last year. The increases primarily resulted from expanding the FES business in Ohio under Ohio's electricity choice program. Internal sales to the regulated services segment decreased $84.0 million in the third quarter but increased $161.0 million in the first nine months of 2003 compared to the same periods of 2002. Energy-related services such as heating, ventilation and air-conditioning work reflected the divestiture in early 2003 of Colonial and Webb, as well as continued declines associated with weak economic conditions. Revenues from energy-related services decreased $77.5 million in the third quarter and $224.6 million in the first nine months of 2003 from the corresponding periods of 2002. Natural gas sales increased $9.7 million in the third quarter and $21.5 million in the first nine months of 2003 from the corresponding periods last year. The increase in gas sales in the third quarter and first nine month of 2003 reflected increased prices which more than offset lower gas volumes delivered as FES focused its operations in a narrower geographic area and on higher-margin gas customers. Expenses increased $188.9 million in the third quarter and $930.4 million in the first nine months of 2003 from the same periods of 2002. Higher other operating expenses ($95.8 million) and purchased power costs ($31.5 million) accounted for the increase in third quarter expenses in 2003 compared to the prior year. Higher pension and benefit costs and additional nuclear operating costs associated with a refueling outage at Beaver Valley Unit 2 - there were no refueling outages in the third quarter of 2002 - contributed to the increase in other operating expenses. The increased purchased power costs reflect higher unit costs. Partially offsetting the increase in third quarter expenses were reduced expenses (excluding an impairment charge) from energy-related businesses which declined $70.1 million in the third quarter of 2003 from the same period last year as a result of the divestiture of Colonial and Webb, and declines associated with weak economic conditions. For the first nine months of 2003, expenses increased $930.4 million from the first nine months of 2002 due to increased purchased power costs ($842.4 million) and additional other operating costs ($169.3 million). Higher unit costs and additional quantities purchased resulted in the large increase in purchase power costs in the first nine months of 2003 from the prior year. Increased volumes resulted from supply obligations assumed by FES for BGS sales, sales to Met-Ed and Penelec in supplying a substantial portion of their PLR requirements, as well as other wholesale commitments, and additional supplies required to replace reduced nuclear generation. Additional costs resulting from the Davis-Besse extended outage, unplanned work performed during two nuclear refueling outages in the second quarter of 2003 and higher employee benefit costs contributed to the increase in other operating expenses. The absence of unusual charges recorded in 2002 moderated the increase in operating expenses by $64.9 million 35
in the 2003 year-to-date period compared to the corresponding period of 2002. Partially offsetting the increase in year-to-date expenses were reduced expenses from energy-related businesses, which declined $212.0 million in the first nine months of 2003 from the same period last year due to the same factors experienced in the third quarter of 2003. A non-cash goodwill impairment charge of $121.5 million ($80.9 million, net of tax) was recognized in the third quarter of 2003 reducing the carrying value of FSG. This charge reflects the continued slow down in the development of competitive retail markets and depressed economic conditions that affect the value of FSG. CAPITAL RESOURCES AND LIQUIDITY FirstEnergy's cash requirements in the fourth quarter of 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without materially increasing FirstEnergy's net debt and preferred stock outstanding. Available borrowing capacity under bank credit facilities will be used to manage working capital requirements. Over the next three years, FirstEnergy expects to meet its contractual obligations with cash from operations. Thereafter, FirstEnergy expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $1.25 billion of revolving credit facilities. In the first nine months of 2003, FirstEnergy received $597.0 million of cash dividends from its subsidiaries and paid $330.8 million in cash common stock dividends to its shareholders. There are currently no material restrictions on the payment of cash dividends by FirstEnergy's subsidiaries. As of September 30, 2003, FirstEnergy had $178.9 million of cash and cash equivalents, compared with $196.3 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from operating activities during the third quarter and first nine months of 2003, compared with the corresponding periods of 2002 were as follows: Three Months Ended Nine Months Ended September 30, September 30, ------------------------------------------- Operating Cash Flows 2003 2002 2003 2002 ------------------------------------------------------------------------ (In millions) Cash earnings (1)........ $551 $478 $1,295 $1,158 Working capital and other .................. 345 190 85 237 ------------------------------------------------------------------------ Total.................... $896 $668 $1,380 $1,395 (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities increased $228 million due to a $155 million change in funds used for working capital and a $73 million increase in cash earnings. The change in funds used for working capital primarily represents offsetting changes for receivables, payables and accrued taxes. Cash Flows From Financing Activities The following table provides details regarding security issuances and redemptions during the third quarter and first nine months of 2003: Securities Issued or Redeemed Three Months Nine Months ------------------------------------------------------------------- (In millions) New Issues Common Stock.......................... $ 935 $ 935 Secured Debt.......................... -- 650 Unsecured Notes....................... -- 331 ------------------------------------------------------------------ $ 935 $1,916 Redemptions First Mortgage Bonds.................. $ 302 $1,002 Pollution Control Notes............... 4 54 Secured Notes......................... 263 491 ------------------------------------------------------------------ $ 569 $1,547 Short-term Borrowings, Net.............. $(799) $ (847) ------------------------------------------------------------------- 36
Net cash used for financing activities increased by $76 million in the third quarter of 2003 from the third quarter of 2002. The increase in funds used for financing activities resulted from increased financing of $108 million that was exceeded by $184 million of additional redemptions and repayments during the third quarter of 2003 compared to the same period of 2002. FirstEnergy had approximately $246.1 million of short-term indebtedness as of September 30, 2003 compared to $1.093 billion at the end of 2002. Available borrowing capability included $1.173 billion under its then existing $1.5 billion revolving lines of credit and $73 million under bilateral bank facilities. As of September 30, 2003, OE, CEI, TE and Penn had the aggregate capability to issue $2.4 billion of additional first mortgage bonds (FMB) on the basis of property additions and retired bonds. JCP&L, Met-Ed and Penelec no longer issue FMB other than as collateral for senior notes, since their senior note indentures prohibit them (subject to certain exceptions) from issuing any debt which is senior to the senior notes. As of September 30, 2003, JCP&L, Met-Ed and Penelec had the aggregate capability to issue $833 million of additional senior notes based upon FMB collateral. Based upon applicable earnings coverage tests and their respective charters, OE, Penn, TE and JCP&L could issue a total of $2.4 billion of preferred stock. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock. On March 17, 2003, FirstEnergy filed a registration statement with the U.S. Securities and Exchange Commission covering securities in the aggregate of up to $2 billion. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, or share purchase contracts and related share purchase units. On September 17, 2003, FirstEnergy completed issuance of 32.2 million shares of common stock at $30 per share, receiving net proceeds of approximately $935 million which were used to reduce bank debt. The issuance used approximately half of the aggregate $2 billion available under the prior shelf registration. In July of 2003, FirstEnergy executed a fixed-for-floating interest rate swap agreement with a notional value of $50 million (see Interest Rate Swap Agreements below) on an underlying JCP&L Senior Note with a fixed interest rate of 4.80%. In October of 2003, FirstEnergy executed two fixed-for-floating interest rate swap agreements with notional values of $50 million each on underlying JCP&L and FE senior notes with an average fixed interest rate of 5.6%. In October 2003, FirstEnergy renewed $1 billion of credit facilities. Combined with an existing $500 million three-year facility for FirstEnergy and an existing $250 million two-year facility for OE, the renewal brings FirstEnergy's primary credit facilities to $1.75 billion. The $1 billion renewal of credit facilities is comprised of components with varying maturities - a 364-day, $375 million facility and three-year, $375 million facility for FirstEnergy; and a 364-day, $125 million facility and three-year $125 million facility for OE. Cash Flows From Investing Activities Net cash used for investing activities totaled $236 million in the third quarter and $462 million in the first nine months of 2003, compared to net cash of $278 million and $475 million, respectively, used for investing activities for the same periods of 2002. The $42 million change in the third quarter of 2003 resulted from the cash investments proceeds in the third quarter of 2003 and decreased capital expenditures. In May 2003, FirstEnergy had reached an agreement to sell its 20.1 percent interest in Avon to Scottish and Southern Energy plc.; subsequently, the agreement was terminated when the parties were unable to agree to terms with representatives of certain bondholders. On October 21, 2003, FirstEnergy announced it reached an agreement to sell its 20.1 percent interest in Avon to a subsidiary of Powergen UK plc, as part of a transaction to include Aquila's 79.9 percent interest. Under terms of the agreement, FirstEnergy would receive approximately $8 million. The sale is contingent upon regulatory approval and reaching agreement with bondholders representing 95% of the aggregate principal amount of the bonds. The holders of approximately half of the outstanding bonds have given their approval. On November 13, 2003, FirstEnergy announced that it had reached an agreement with NRG covering the settlement of its claims resulting from the uncompleted sale of four FirstEnergy power plants to NRG (see Note 3 - Divestitures: Sale of Generating Assets). Under the agreement FirstEnergy would receive an estimated settlement of approximately $198 million in the form of cash (12%), notes (15.2%) and common stock (72.8%). The agreement is subject to FERC authorization and U.S. Bankruptcy Court approval since NRG and certain of its subsidiaries filed for voluntary bankruptcy in May 2003. The following table summarizes investments made in the third quarter and first nine months of 2003 by FirstEnergy's regulated services and competitive services segments: 37
<TABLE> <CAPTION> Property Summary of Cash Used for Investing Activities Additions Investments Other Total - --------------------------------------------------------------------------------------------- Sources (Uses) (In millions) <S> <C> <C> <C> <C> Three Months Ended September 30, 2003 Regulated Services........................... $ (63)(1) $ (84) $ 2 $(145) Competitive Services......................... (88)(2) (37) 16 (109) Other........................................ (5) 30 (7) 18 Eliminations................................. -- -- -- -- - --------------------------------------------------------------------------------------------- Total............................... $(156) $ (91) $ 11 $(236) ============================================================================================= Nine Months Ended September 30, 2003 Regulated Services........................... $(218)(1) $ (17)(3) $ 26 $(209) Competitive Services......................... (302 (2) 27 (4) (77) (352) Other........................................ (60) -- 99 (5) 39 Eliminations................................. -- -- 60 60 - -------------------------------------------------------------------------------------------- Total............................... $(580) $ 10 $108 $(462) ============================================================================================ <FN> (1) Property additions primarily for transmission and distribution facilities. (2) Property additions to generation facilities. (3) Net of several items from cash investments and NUG trust offset in part by investments in nuclear decommissioning trusts. (4) Sale of assets - includes Colonial and Webb sale. (5) Primarily a change in OCI from Emdersa abandonment (see Note 3). </FN> </TABLE> During the fourth quarter of 2003, capital requirements for property additions and capital leases are expected to be approximately $209 million. FirstEnergy has additional requirements of approximately $21 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI, and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the securities of its electric utility operating companies. Fitch stated that the changes to the long-term ratings were "driven by the high debt leverage of the parent FE. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been vulnerable to unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable Outlook reflects the success of FE's recent common equity offering and management's focus on a relatively conservative integrated utility strategy." On October 27, 2003, Standard & Poors (S&P) stated that the `BBB' corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its utility subsidiaries remain on CreditWatch with negative implications. The ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's concerns regarding the potential impact of the August 14, 2003 blackout investigation on FirstEnergy's deleveraging strategy and its overall efforts to improve its credit profile. At that time, S&P also noted other challenges facing FirstEnergy, including the extended Davis-Besse outage; the recent U.S. District Court ruling regarding the Sammis Plant (see Outlook-Environmental Matters below); reliability concerns in subsidiary JCP&L's service territory; and FirstEnergy's credibility with regulators and federal officials. S&P further noted several factors that could aid FirstEnergy in resolution of the CreditWatch, including strengthening its balance sheet. FirstEnergy directly addressed this concern through its recently completed common equity offering that raised approximately $935 million in net proceeds, which was used to reduce bank debt. See Cash Flows from Financing Activities above. S&P described the equity offering as a "positive credit development" and also noted the recent renewal of FirstEnergy's $1 billion revolver facilities as a "favorable development, as it mitigates liquidity 38
concerns." S&P also indicated that should various ongoing investigations into the causal factors of the August 14, 2003 blackout establish that the blackout resulted from no negligence or breach of compliance standards on FirstEnergy's part, the CreditWatch could be removed and the outlook returned to negative. S&P deemed a "stable" credit outlook unlikely until issues such as the restart of Davis-Besse are resolved and the potential effect of the litigation relating to the Sammis plant (the second trial is scheduled for April 2004) are known. Extension of the Ohio transition plan will be viewed as a positive development and will support an outlook revision to stable. On October 27, 2003, S&P also noted that the ratings on FirstEnergy and its subsidiaries incorporate such strengths as the ability to generate free cash flow, power generation contracted to its transmission and distribution subsidiaries through 2005, and the hedging of its short power position arising from its PLR obligation in Pennsylvania. S&P said that these strengths are offset by slower than anticipated reduction of FirstEnergy debt, remaining volume risks of PLR obligations, the extended outage at Davis-Besse, the unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty in Ohio. S&P also said that it now views FirstEnergy's liquidity position as average, following FirstEnergy's renewal of its $1 billion credit facilities. OTHER OBLIGATIONS Obligations not included on FirstEnergy's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant. As of September 30, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.4 billion. Also, CEI and TE continue to sell substantially all of their retail customer receivables, which provided $200 million of financing not included on the Consolidated Balance Sheet as of September 30, 2003. GUARANTEES AND OTHER ASSURANCES As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and ratings contingent collateralization provisions. As of September 30, 2003, the maximum potential future payments under outstanding guarantees and other assurances totaled approximately $1.0 billion as summarized below: Maximum Guarantees and Other Assurances Exposure ----------------------------------------------------------- (In millions) FirstEnergy Guarantees of Subsidiaries(1) Energy and Energy-Related Contracts(2)...... $ 793.3 Other (3)................................... 162.7 ---------------------------------------------------------- 956.0 Surety Bonds.................................. 15.6 Rating-Contingent Collateralization (3)....... 64.2 ---------------------------------------------------------- Total Guarantees and Other Assurances....... $1,035.8 ========================================================== (1) Estimated net liabilities under contracts subject to rating-contingent collateralization provisions that total $185.7 million. (2) Issued for a one-year term, with a 10-day termination right by FirstEnergy. (3) Issued for various terms. FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by FirstEnergy's other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with energy-related activities is remote. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions. 39
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. MARKET RISK INFORMATION FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk FirstEnergy is exposed to market risk primarily due to fluctuations in electricity, natural gas and coal prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. Most of FirstEnergy's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the third quarter and first nine months of 2003 is summarized in the following table: <TABLE> <CAPTION> INCREASE (DECREASE) IN THE FAIR VALUE OF COMMODITY DERIVATIVE CONTRACTS - ------------------------------------- Three Months Ended Nine Months Ended September 30, 2003 September 30, 2003 --------------------------- -------------------------- Non-Hedge Hedge Total Non-Hedge Hedge Total --------- ----- ----- --------- ----- ----- (In millions) <S> <C> <C> <C> <C> <C> <C> Change in the Fair Value of Commodity Derivative Contracts Net asset at beginning of period....................... $66.0 $ 35.5 $101.5 $53.8 $ 24.1 $ 77.9 New contract value when entered........................ -- -- -- -- -- -- Change in value of existing contracts.................. (4.7) (9.7) (14.4) 11.2 27.7 38.9 Change in techniques/assumptions....................... 9.4 -- 9.4 9.4 -- 9.4 Settled contracts...................................... 16.0 (19.3) (3.3) 12.3 (45.3) (33.0) ------------------------- ------------------------- Net asset at end of period (1)......................... 86.7 6.5 93.2 86.7 6.5 93.2 ------------------------- ------------------------- Non-commodity net assets at end of period: Interest Rate Swaps (2)............................. -- 5.9 5.9 -- 5.9 5.9... ------------------------- ------------------------- Net Assets - Derivative Contracts at end of period (3). $86.7 $ 12.4 $ 99.1 $86.7 $ 12.4 $ 99.1 ========================= ========================= Impact of Changes in Commodity Derivative Contracts (4) Income Statement Effects (Pre-Tax)..................... $20.2 $ -- $ 20.2 $ 7.8 $ -- $ 7.8 Balance Sheet Effects: Other Comprehensive Income (Pre-Tax)................ $ -- $(29.0) $(29.0) $ -- $(17.6) $(17.6) Regulatory Liability................................ $ 0.5 $ -- $ 0.5 $25.1 $ -- $ 25.1 <FN> (1) Includes $59.2 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 $14.1 million of derivative contract fair value decrease, as of September 30, 2003, representing FirstEnergy's 50% share of Great Lakes Energy Partners, LLC. (4) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. </FN> </TABLE> Derivatives are included on the Consolidated Balance Sheet as of September 30, 2003 as follows: Non-Hedge Hedge Total - --------------------------------------------------------------------- (In millions) Current- Other Assets...................... $ 6.8 $ 3.4 $ 10.2 Other Liabilities................. (8.2) (1.1) (9.3) Non-Current- Other Deferred Charges............ 88.8 15.2 104.0 Other Deferred Credits............ (0.7) (5.1) (5.8) - --------------------------------------------------------------------- Net assets........................ $86.7 $12.4 $ 99.1 ===================================================================== 40
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 commodity derivative contracts by year are summarized in the following table: <TABLE> <CAPTION> Source of Information - Fair Value by Contract Year 2003(1) 2004 2005 2006 Thereafter Total - -------------------------------------------------------------------------------------------------------------- (In millions) <S> <C> <C> <C> <C> <C> <C> Prices actively quoted(2)............. $0.8 $ 4.4 $(0.4) $-- $-- $ 4.8 Other external sources(3)............. 0.7 20.6 10.5 -- -- 31.8 Prices based on models................ -- -- -- 13.1 43.5 56.6 - ----------------------------------------------------------------------------------------------------------- Total(4)........................... $1.5 $25.0 $10.1 $13.1 $43.5 $93.2 =========================================================================================================== <FN> (1) For the last quarter of 2003. (2) Exchange traded. (3) Broker quote sheets. (4) Includes $59.2 million from an embedded option that is offset by a regulatory liability and does not affect earnings. </FN> </TABLE> FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on both FirstEnergy's trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of September 30, 2003. Based on derivative contracts held as of September 30, 2003, an adverse 10% change in commodity prices would decrease net income by approximately $4.7 million during the next twelve months. Interest Rate Swap Agreements During the third quarter of 2003, FirstEnergy entered into a fixed-to-floating interest rate swap agreement, 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 fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, fixed interest rates and interest payment dates match those of the underlying obligations. The swap agreement consummated in the third quarter of 2003 is based on a notional principal amount of $50 million. As of September 30, 2003, the debt underlying FirstEnergy's $600 million notional amount of outstanding fixed-for-floating interest rate swaps had a weighted average fixed interest rate of 5.62%, which the swaps have effectively converted to a current weighted average variable interest rate of 2.24%. GPU Power (through a subsidiary) used existing dollar-denominated interest rate swap agreements in the first nine months of 2003. The GPU Power agreements convert variable-rate debt to fixed-rate debt to manage the risk of increases in variable interest rates. GPU Power's swaps had a weighted average fixed interest rate of 6.68% as of September 30, 2003 and December 31, 2002. The following summarizes the principal characteristics of the swap agreements: <TABLE> <CAPTION> September 30, 2003 December 31, 2002 ---------------------------- ----------------------------- Notional Maturity Fair Notional Maturity Fair Interest Rate Swaps Amount Date Value Amount Date Value ------------------------------------------------------------------ (Dollars in millions) <S> <C> <C> <C> <C> <C> <C> Fixed to Floating Rate (Fair value hedges) $200 2006 $ 4.7 50 2008 0.5 150 2015 (5.8) $444 2023 $15.5 50 2018 0.7 -- -- -- 150 2025 6.3 150 2025 5.9 Floating to Fixed Rate (Cash flow hedges) $ 8 2005 $(0.5) $ 16 2005 $(0.9) - ---------------------------------------------------------------------------------------------- </TABLE> Equity Price Risk Included in FirstEnergy's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $669 million and $532 million as of September 30, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $67 million reduction in fair value as of September 30, 2003. 41
OUTLOOK FirstEnergy continues to pursue its goal of being the leading regional supplier of energy and related services in the northeastern quadrant of the United States, where it sees the best opportunities for growth. Its fundamental business strategy remains stable and unchanged. While FirstEnergy continues to build toward a strong regional presence, key elements for its strategy are in place and management's focus continues to be on execution. FirstEnergy intends to provide competitively priced, high-quality products and value-added services - energy sales and services, energy delivery, power supply and supplemental services related to its core business. As FirstEnergy's industry changes to a more competitive environment, FirstEnergy has taken and expects to take actions designed to create a larger, stronger regional enterprise that will be positioned to compete in the changing energy marketplace. FirstEnergy's current focus includes: 1) returning Davis-Besse to safe and reliable operation; 2) optimizing FirstEnergy's generation portfolio; 3) effectively managing commodity supplies and risks; 4) reducing FirstEnergy's cost structure; and 5) enhancing its credit profile and financial flexibility. Business Organization FirstEnergy's business is managed as two distinct operating segments - - a competitive services segment and a regulated services segment. FES provides competitive retail energy services while the EUOC provide regulated transmission and distribution services. FirstEnergy Generation Corp. (FGCO), a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and operates those plants. FirstEnergy expects the transfer of ownership of EUOC non-nuclear generating assets to FGCO will be substantially completed by the end of the 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. State Regulatory Matters In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in the EUOCs' 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 EUOCs' electric customers to select their generation suppliers; o establishing PLR obligations to non-shopping customers in the EUOCs' service areas; o allowing recovery of potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; o itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; o deregulating the EUOCs' electric generation businesses; and o continuing regulation of the EUOCs' transmission and distribution systems. Regulatory assets are costs that the respective regulatory agencies have authorized for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of the regulatory assets are expected to continue to be recovered under the provisions of the respective transition and regulatory plans discussed below. Regulatory assets declined by $954.6 million for the first nine months of 2003, to $7.8 billion as of September 30, 2003. Over one-half of the reduction in regulatory assets resulted from the costs disallowed in the JCP&L rate case decision and adoption of SFAS 143 by JCP&L, Met-Ed, Penelec and Penn. The regulatory assets of the individual companies are as follows: 42
Regulatory Assets ------------------------------------------------ September 30, December 31, Company 2003 2002 ------------------------------------------------ (In millions) OE............... $1,594.0 $1,848.7 CEI.............. 1,138.2 1,191.8 TE............... 516.3 578.2 Penn............. 50.1 156.9 JCP&L............ 2,926.7 3,199.0 Met-Ed........... 1,059.8 1,179.1 Penelec.......... 513.7 599.7 ---------------------------------------------- Total............ $7,798.8 $8,753.4 ============================================== Ohio FirstEnergy's transition plan (which FirstEnergy filed on behalf of its Ohio electric utilities) included approval for recovery of transition costs, including regulatory assets, as filed in the transition plan through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The approved plan also granted preferred access over FirstEnergy's subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 megawatts of generation capacity through 2005 at established prices for sales to the Ohio Companies' retail customers. Customer prices are frozen through a five-year market development period (2001-2005), except for certain limited statutory exceptions including a 5% reduction in the price of generation for residential customers. In February 2003, the Ohio electric utilities were authorized increases in revenues aggregating approximately $50 million (OE-$41 million, CEI-$4 million and TE-$5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation. FirstEnergy's Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers - recovery will be accomplished by extending the respective transition cost recovery periods. On October 21, 2003, the Ohio Companies 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 supply and continuing FirstEnergy's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service, including PLR responsibility, for FirstEnergy's Ohio 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 FirstEnergy's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity as discussed above. In order to facilitate supply planning, FirstEnergy has requested that the PUCO rule on this proposal by December 31, 2003. Under the proposed plan, FirstEnergy is requesting: o Extension of the transition cost amortization period for OE from 2006 to 2007; for CEI from 2008 to 2009 and for TE from mid-2007 to 2008; o Deferral of new regulatory assets and deferral of interest costs on the shopping incentive and other new deferrals; o Ability to initiate a request to increase generation rates only under certain limited conditions. As a result of the Ohio Companies' October 21 filing, the PUCO entered an order on October 28, 2003 setting forth the discovery schedule related to the application with hearings scheduled to begin December 3, 2003. 43
New Jersey Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L submitted two rate filings with the NJBPU in August 2002. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization 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 percent on JCP&L's rate base for 6 to 12 months. During that period, JCP&L will initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75 percent or decrease it to 9.25 percent, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The 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 charge. 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 nine months ended September 30, 2003, aggregating $172 million ($103 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 which is expected to be issued in the fourth quarter of 2003. Pennsylvania Effective September 1, 2002, Met-Ed and Penelec assigned their PLR responsibility to FES through a wholesale power sale which expires in December 2003 and may be extended for each successive calendar year. Under the terms of the wholesale agreement, FES assumed the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other 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 to FES. FES has hedged most of Met-Ed's and Penelec's unfilled on-peak PLR obligation through 2004 and a portion of 2005. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices. 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 Administrative Law Judge 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 competitive transition charge (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 order on two issues: to establish the end of June 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 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. Met-Ed and Penelec are considering filing an appeal to the Commonwealth Court on the PPUC orders as well. 44
On October 27, 2003, one Commonwealth Court judge issued an order denying Met-Ed's and Penelec's objections 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 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 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. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FirstEnergy is also accelerating maintenance work that had been planned for future refueling and maintenance outages. Testing of the bottom of the reactor for leaks was completed in October 2003 and no indication of leakage was discovered. FirstEnergy is installing a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FirstEnergy anticipates that the unit will be ready for restart in the fall of 2003. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed FirstEnergy's plans to reduce post-merger debt levels FirstEnergy believes such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). Incremental costs associated with the extended Davis-Besse outage for the third quarter and first nine months of 2003 and 2002 were as follows: Three Months Ended Nine Months Ended ------------------ ----------------- Costs of Davis-Besse Extended Outage September 30, September 30 - -------------------------------------------------------------------------------- 2003 2002 2003 2002 ---- ---- ---- ---- (In millions) Incremental Pre-Tax Expense Replacement power................. $54.9 $50.9 $148.4 $ 84.5 Maintenance....................... 17.5 39.8 75.7 54.1 - -------------------------------------------------------------------------------- Total......................... $72.4 $90.7 $224.1 $138.6 ================================================================================ Capital Expenditures................ $10.9 $27.4 $ 13.3 $ 39.4 ================================================================================ It is anticipated that an additional $14 million in maintenance costs will be expended over the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month during the remaining period of the outage. FirstEnergy has hedged the on-peak replacement energy supply for Davis-Besse for the expected length of the outage. If there are significant delays in the NRC approval process, substantial replacement power costs will continue to be incurred, which will continue to have an adverse effect on FirstEnergy's, CEI's and TE's respective cash flows and results of operations. Environmental Matters Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $159 million, which is included in the construction forecast provided under "Capital Expenditures" for 2003 through 2007. The Companies are required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. 45
The Companies believe they are in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that required compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone emissions and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals for the D.C. Circuit found constitutional and other defects in the new NAAQS rules. In February 2001, the U.S. Supreme Court upheld the new NAAQS rules regulating ultra-fine particulates but found defects in the new NAAQS rules for ozone and decided that the EPA must revise those rules. The future cost of compliance with these regulations may be substantial and will depend if and how they are ultimately implemented by the states in which the Companies operate affected facilities. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The civil complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning April 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 Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been recorded as of September 30, 2003. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. Several EUOCs have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2003, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through the SBC. The Companies have total accrued liabilities aggregating approximately $50.4 million as of September 30, 2003. The effects of compliance on the EUOCs with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings 46
and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Power Outage On August 14, 2003, eight states and southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. The cause of the outage has not been determined. FirstEnergy continues to accumulate data and evaluate the status of its electrical system prior to and during the outage event. On September 12, 2003, the U.S./Canada Power Outage Task Force (Task Force) investigating the August 14 outage released a timeline of events. The timeline presented the sequence of events that occurred on major transmission lines (230 kilovolts or greater) and at large power plants beginning at approximately noon through approximately 4:00 PM, preceding the outage. This timeline did not attempt to present or explain the linkages between the sequence of events. Determining the specific causes of the events and their relation to the outage will require more time to analyze by the Task Force. The Task Force is expected to release its interim report on November 18, 2003. Legal Matters As of October 14, 2003, ten individual shareholder-plaintiffs have filed separate complaints against FirstEnergy alleging various securities law violations. The bases for these complaints vary but include alleged violations arising out of the power outage, described herein, the extended outage at Davis-Besse, and the restatement of earnings, described herein. FirstEnergy is reviewing the suits that have been served in preparation for a responsive pleading. FirstEnergy is, however, aware that in each case, the plaintiffs are seeking certification from the court to represent a class of similarly situated shareholders. In addition, four shareholder-plaintiffs have filed "shareholder derivative" actions against the members of the Board of Directors, and the Company as a nominal defendant, asserting rights of the corporation itself. The complaints allege violations of fiduciary duties as a result of, generally, the same events described in the securities lawsuits described herein. Furthermore, five lawsuits - three in Ohio state courts, two in New York state courts - have been filed seeking damages relating to the August 14, 2003 power outage. The two New York actions name FirstEnergy as one of several defendants and have been noticed but not served. Additionally, a complaint has been filed with the PUCO by United States Congressman Dennis Kucinich, alleging that as a result of several events, including the August 14, 2003 power outage and the extended outage at Davis-Besse, both described herein, the Company has failed to provide adequate and reasonable service to its customers. That complaint asks, among other things, that another electric supplier be authorized to provide service within the Ohio Utilities' certified territories. FirstEnergy believes that in each instance, the legal actions are without merit. FirstEnergy intends to defend these actions vigorously, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be instituted against it. In particular, if FirstEnergy were ultimately determined to have legal liability in connection with the outage, it could have a material adverse effect on FirstEnergy's financial condition and results of operations. Various lawsuits, claims and proceedings related to FirstEnergy's normal business operations are pending against it, the most significant of which are described herein. SIGNIFICANT ACCOUNTING POLICIES FirstEnergy prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of FirstEnergy's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. FirstEnergy's more significant accounting policies are described below. Regulatory Accounting FirstEnergy's regulated services segment is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine FirstEnergy is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in each state in which FirstEnergy operates, a significant amount of regulatory assets have been recorded - $7.8 billion as of September 30, 2003. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. 47
Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. FirstEnergy continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, FirstEnergy enters into significant commodity contracts, as well as interest rate and currency swaps, which increase the impact of derivative accounting judgments. Revenue Recognition FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension and OPEB benefits are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used at the end of 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. Beginning in 2003, the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy is not required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends 48
have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's restructuring 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, "Accounting for the Impairment or Disposal of Long-Lived Assets," FirstEnergy periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, FirstEnergy recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. When 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. 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 $121.5 million was recognized in the third quarter of 2003, reducing the carrying value of FSG. That charge reflects the continued slow down in the development of competitive retail markets and depressed economic conditions that affect the 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 September 30, 2003, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. A summary of the changes in FirstEnergy's goodwill for the nine months ended September 30, 2003 (which affected only the Competitive Services Segment) is shown below: (In millions) Balance at December 31, 2003............ $6,278.1 Impairment charges...................... (121.5) FSG divestitures........................ (40.8) Other................................... 12.1 -------- Balance at September 30, 2003........... $6,127.9 ======== NEW ACCOUNTING STANDARDS ADOPTED SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the 49
beginning of the first interim period beginning after June 15, 2003 (FirstEnergy's third quarter of 2003) for all other financial instruments. Upon adoption of SFAS 150, effective July 1, 2003, FirstEnergy reclassified as debt the preferred stock of consolidated subsidiaries subject to mandatory redemptions with a carrying value of approximately $17.5 million ($4.0 million for CEI and $13.5 million for Penn) as of September 30, 2003. Subsidiary-obligated mandatorily redeemable preferred securities of $285 million ($100 million for CEI, $93 million for Met-Ed and $92 for Penelec) were also reclassified and included in long-term debt as of September 30, 2003. As required by SFAS 150, the preferred securities subject to mandatory redemption were not restated as long-term debt on the December 31, 2002 balance sheet. Adoption of SFAS 150 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. Dividends on preferred stock subject to mandatory redemption on CEI and Penn's respective Consolidated Statements of Income, which were not included in net interest charges prior to the adoption of SFAS 150, were included in net interest charges for the three months ended September 30, 2003. CEI, Met-Ed and Penelec created statutory business trusts to issue the preferred securities of $285 million discussed above. The continued consolidation of the issuer trusts and the appropriate balance sheet classification of the trust preferred securities is currently under review pursuant to FIN 46 (see Note 6). Upon the implementation of FIN 46 effective December 31, 2003, these trusts would be deconsolidated if CEI, Met-Ed and Penelec were not the primary beneficiaries of the related trusts. Rather than recording a liability for the trust preferred securities as discussed above, FirstEnergy, CEI, Met-Ed and Penelec would reflect liabilities for the notes payable to the respective trusts, which are currently eliminated in consolidation. The deconsolidation of the trusts would result in an increase to total assets and liabilities of $9.3 million ($3.1 million for each of CEI, Met-Ed and Penelec) for the investment in the trusts. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS 133 for decisions made by the Derivative Implementation Group (DIG), as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for reporting periods beginning before June 15, 2003, that continue to be applied based on their original effective dates. Adoption of SFAS 149 did not have a material impact on the Company's financial statements. SFAS 143, "Accounting for Asset-Retirement Obligations" The Company adopted SFAS 143 effective January 1, 2003. The impact of this new accounting standard is discussed above under Results of Operations. EITF Issue No. 01-8, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus on Issue No. 01-8, regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus is to be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. The adoption of this consensus as of July 1, 2003 did not impact FirstEnergy's financial statements. EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" In October 2002, the EITF reached a consensus that for periods after July 15, 2002, mark-to-market revenues and expenses and their related kilowatt-hour sales and purchases on energy trading contracts must be shown on a net basis on the Consolidated Statements of Income. FirstEnergy had previously reported such contracts as gross revenues and purchased power costs. Comparative quarterly disclosures and the Consolidated Statements of Income for revenues and expenses have been reclassified for 2002 to conform with the revised presentation. In addition, the related kilowatt-hour sales and purchases statistics described above under Results of Operations were reclassified (2.7 billion kilowatt-hours in the third quarter and 5.3 billion kilowatt-hours in the first nine months of 2002). The following table displays the impact of changing to a net presentation for FirstEnergy's energy trading operations. 50
<TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ------------------------ ------------------------ Impact of Recording Energy Trading Net Revenues Expenses Revenues Expenses - --------------------------------------------------------------------------------------------------- (In millions) <S> <C> <C> <C> <C> Total as originally reported................. $3,572 $2,845 $9,414 $7,570 Adjustment................................... (121) (121) (211) (211) - ---------------------------------------------------------------------------------------------------- Total as currently reported.................. $3,451 $2,724 $9,203 $7,359 =================================================================================================== </TABLE> NEW ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". This Interpretation requires the consolidation of a variable interest entity (VIE) by an enterprise if that enterprise either absorbs a majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns as a result of ownership, contractual or other financial interests in the VIE. Currently, entities are generally consolidated by an enterprise that has a controlling financial interest through ownership of a majority voting interest in the entity. FIN 46 defines a VIE as an entity in which equity investors do not have the characteristics of a controlling financial interest nor have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. VIE's created after January 31, 2003, are immediately subject to the provisions of FIN 46. The FASB recently deferred implementation of FIN 46 for VIE's created before February 1, 2003, until the first reporting period ending after December 15, 2003 (FirstEnergy's quarter ending December 31, 2003.) FirstEnergy currently has transactions with entities in connection with sale and leaseback arrangements which fall within the scope of this interpretation and which meet the definition of a VIE in accordance with FIN 46. In addition to the two entities created to refinance debt discussed below, the Company is evaluating its interest in the owner trusts that acquired certain interests in the Perry Plant, Beaver Valley Unit 2 and the Bruce Mansfield Plant. 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. FirstEnergy is exposed to losses under the sale-leaseback agreements upon the occurrence of certain contingent events that we consider unlikely to occur. The Company's maximum exposure to loss is currently estimated to be $2.0 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the plants worthless. Under the sale and leaseback agreements, FirstEnergy has minimum undiscounted net lease payments of $2.6 billion that would not be payable if the casualty value payments are made. In addition, the Company has recorded above market lease obligations of $1.1 billion related to the Bruce Mansfield Plant and Beaver Valley Unit 2 as of September 30, 2003 (see Note 1) related to the acquisition by FirstEnergy of CEI and TE. FirstEnergy currently believes that it will consolidate two VIE's created in 1996 and 1997 to refinance debt in connection with the above sale and leaseback transactions. In 1996, the PNBV Capital Trust issued equity and notes to fund the acquisition of a portion of the collateralized lease bonds that had been issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by the PNBV Trust. Ownership of the trust 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 the trust as of December 31, 2002 would have changed the PNBV trust investment of $389 million to an investment in collateralized lease bonds of $401 million. The increase in $12 million would have represented the minority interest in the total assets of the trust. In 1997, CEI and TE established the Shippingport Capital Trust to purchase all of the lease obligation bonds issued by the owner trusts in the Bruce Mansfield Plant sale and leaseback transactions. CEI and TE acquired all of the notes issued by Shippingport Capital Trust. The equity ownership of this trust includes a 0.34% interest held by Toledo Edison Capital Corporation (TECC), a wholly owned subsidiary of TE, and a 2.25% interest and a 2.60% interest held by unaffiliated third parties. The assets and liabilities of the trust are currently included on a proportionate basis in the financial statements of CEI and TE. Adoption of FIN 46 will not impact FirstEnergy with respect to this trust, but may result in reporting all of the trust assets and liabilities on the books of CEI. As described in Note 1, the consolidated financial statements of FirstEnergy, CEI, Met-Ed and Penelec currently include several trusts that have sold trust preferred securities in which FirstEnergy is not the primary beneficiary. Pending further guidance from the FASB that would indicate otherwise, these entities may not be consolidated in FirstEnergy's financial statements as of December 31, 2003. The deconsolidation would result in an increase to total assets and liabilities of $9.3 million ($3.1 million for each of CEI, Met-Ed and Penelec) for the investment in the trusts. 51
The FASB continues to provide additional guidance on implementing FIN 46 and recently proposed modifications and clarifications with a comment period ending December 1, 2003. As this guidance is finalized, the Company will continue to assess the accounting and disclosure impact of FIN 46 with respect to the VIE's discussed above as well as other potential VIE's. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003, which would correspond to FirstEnergy's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence of a general index, such as the Consumer Price Index, in a contract would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. FirstEnergy is currently assessing the new guidance but does not anticipate any material impact on its financial statements. 52
<TABLE> <CAPTION> OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, --------------------- ----------------------- 2003 2002 2003 2002 -------- -------- ---------- ---------- Restated Restated (See Note 1) (See Note 1) (In thousands) <S> <C> <C> <C> <C> OPERATING REVENUES........................................ $774,859 $813,296 $2,191,310 $2,265,645 -------- -------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel................................................... 13,978 15,649 37,118 45,068 Purchased power........................................ 231,619 243,475 691,802 698,126 Nuclear operating costs................................ 98,742 79,388 342,319 255,322 Other operating costs.................................. 107,509 94,820 278,109 252,928 -------- -------- ---------- ---------- Total operation and maintenance expenses........... 451,848 433,332 1,349,348 1,251,444 Provision for depreciation and amortization............ 121,734 90,991 335,872 273,932 General taxes.......................................... 46,863 47,254 139,525 135,154 Income taxes........................................... 66,453 92,941 144,533 215,506 -------- -------- ---------- ---------- Total operating expenses and taxes................. 686,898 664,518 1,969,278 1,876,036 -------- -------- ---------- ---------- OPERATING INCOME.......................................... 87,961 148,778 222,032 389,609 OTHER INCOME.............................................. 16,439 14,212 45,351 29,811 -------- -------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES........................ 104,400 162,990 267,383 419,420 -------- -------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt............................. 21,241 29,548 70,686 92,933 Allowance for borrowed funds used during construction and capitalized interest............................. (1,668) (1,018) (4,172) (2,522) Other interest expense................................. 3,144 2,889 14,947 10,837 Subsidiaries' preferred stock dividend requirements.... 911 2,276 2,735 9,528 -------- -------- ---------- ---------- Net interest charges............................... 23,628 33,695 84,196 110,776 -------- -------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE.................................................... 80,772 129,295 183,187 308,644 Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 5)......................... -- -- 31,720 -- -------- -------- ---------- ---------- NET INCOME................................................ 80,772 129,295 214,907 308,644 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 659 658 1,977 5,851 -------- -------- ---------- ---------- EARNINGS ON COMMON STOCK.................................. $ 80,113 $128,637 $ 212,930 $ 302,793 ======== ======== ========== ========== <FN> The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements. </FN> </TABLE> 53
<TABLE> <CAPTION> OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------- (See Note 1) (In thousands) ASSETS ------ <S> <C> <C> UTILITY PLANT: In service................................................................. $5,220,708 $4,989,056 Less-Accumulated provision for depreciation................................ 2,620,419 2,552,007 ---------- ---------- 2,600,289 2,437,049 ---------- ---------- Construction work in progress- Electric plant........................................................... 136,075 122,741 Nuclear fuel............................................................. 16,390 23,481 ---------- ---------- 152,465 146,222 ---------- ---------- 2,752,754 2,583,271 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: PNBV Capital Trust......................................................... 387,770 402,565 Letter of credit collateralization......................................... 277,763 277,763 Nuclear plant decommissioning trusts....................................... 346,378 293,190 Long-term notes receivable from associated companies....................... 509,684 503,827 Other...................................................................... 65,678 74,220 ---------- ---------- 1,587,273 1,551,565 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents.................................................. 1,792 20,512 Receivables- Customers (less accumulated provisions of $8,635,000 and $5,240,000, respectively for uncollectible accounts)................... 281,801 296,548 Associated companies..................................................... 668,273 592,218 Other (less accumulated provisions of $1,000,000 for uncollectible accounts at both dates)................................................ 29,169 30,057 Notes receivable from associated companies................................. 577,822 437,669 Materials and supplies, at average cost- Owned.................................................................... 58,799 58,022 Under consignment........................................................ 14,261 19,753 Prepayments and other...................................................... 18,089 11,804 ---------- ---------- 1,650,006 1,466,583 ---------- ---------- DEFERRED CHARGES: Regulatory assets.......................................................... 1,644,158 2,005,554 Property taxes............................................................. 59,035 59,035 Unamortized sale and leaseback costs....................................... 66,978 72,294 Other...................................................................... 59,223 51,739 ---------- ---------- 1,829,394 2,188,622 ---------- ---------- $7,819,427 $7,790,041 ========== ========== </TABLE> 54
<TABLE> <CAPTION> OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------- (See Note 1) (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ <S> <C> <C> 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..................................... (98,638) (59,495) Retained earnings........................................................ 633,951 800,021 ---------- ---------- Total common stockholder's equity.................................... 2,634,042 2,839,255 Preferred stock not subject to mandatory redemption........................ 60,965 60,965 Preferred stock of consolidated subsidiary- Not subject to mandatory redemption...................................... 39,105 39,105 Subject to mandatory redemption (Note 5)................................. -- 13,500 Long-term debt and other long-term obligations- Preferred stock of consolidated subsidiary subject to mandatory redemption (Note 5) ................................................... 13,500 -- Other.................................................................... 1,477,530 1,219,347 ---------- ---------- 4,225,142 4,172,172 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock....................... 417,216 563,267 Short-term borrowings- Associated companies..................................................... 9,947 225,345 Other.................................................................... 174,578 182,317 Accounts payable- Associated companies..................................................... 268,214 145,981 Other.................................................................... 3,537 18,015 Accrued taxes.............................................................. 646,668 466,064 Accrued interest........................................................... 22,686 28,209 Other...................................................................... 107,596 74,562 ---------- ---------- 1,650,442 1,703,760 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes.......................................... 864,355 1,017,629 Accumulated deferred investment tax credits................................ 78,977 88,449 Asset retirement obligation................................................ 312,560 -- Nuclear plant decommissioning costs........................................ -- 280,858 Retirement benefits........................................................ 405,088 247,531 Other...................................................................... 282,863 279,642 ---------- ---------- 1,943,843 1,914,109 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)............................ ---------- ---------- $7,819,427 $7,790,041 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets. </FN> </TABLE> 55
<TABLE> <CAPTION> OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, --------------------- ----------------------- 2003 2002 2003 2002 -------- -------- ---------- ---------- Restated Restated (See Note 1) (See Note 1) (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 80,772 $ 129,295 $ 214,907 $ 308,644 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 121,734 90,991 335,872 273,932 Nuclear fuel and capital lease amortization........ 10,542 12,389 28,411 35,924 Deferred operating lease costs, net................ 33,977 32,908 31,300 32,726 Deferred income taxes, net......................... (30,010) (12,682) (50,714) (39,838) Amortization of investment tax credits............. (3,681) (3,427) (11,077) (10,315) Accrued retirement benefit obligations............. 20,471 6,325 31,652 6,143 Accrued compensation, net.......................... 366 5,651 (8,111) 3,757 Cumulative effect of accounting change (Note 5).... -- -- (54,109) -- Receivables........................................ 329,852 (18,352) (50,930) 14,451 Materials and supplies............................. (956) (3,699) 4,715 (8,499) Accounts payable................................... (141,910) 18,690 113,508 (771) Accrued taxes...................................... 131,470 16,302 180,604 222,562 Accrued interest................................... (417) 1,926 (5,523) (37) Prepayments and other current assets............... 3,514 1,791 (6,285) 33,064 Other.............................................. (1,238) (3,718) 28,313 (36,413) --------- --------- ---------- ---------- Net cash provided from operating activities...... 554,486 274,390 782,533 835,330 --------- --------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... -- 14,500 575,000 14,500 Short-term borrowings, net........................... -- 348,132 -- 321,974 Redemptions and Repayments- Preferred stock...................................... -- (220,000) -- (220,000) Long-term debt....................................... (209,111) (182,595) (467,567) (411,336) Short-term borrowings, net........................... (4,547) -- (223,137) -- Dividend Payments- Common stock......................................... (94,000) (20,700) (379,000) (121,900) Preferred stock...................................... (659) (658) (1,977) (5,851) --------- --------- ---------- ----------- Net cash used for financing activities .......... (308,317) (61,321) (496,681) (422,613) --------- --------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... (39,432) (32,130) (141,126) (87,851) Notes receivable from associated companies, net........ (197,289) (165,340) (146,010) (300,119) Other.................................................. (10,020) 6,047 (17,436) 16,450 --------- --------- ---------- ---------- Net cash used for investing activities........... (246,741) (191,423) (304,572) (371,520) --------- --------- ---------- ---------- Net increase (decrease) in cash and cash equivalents...... (572) 21,646 (18,720) 41,197 Cash and cash equivalents at beginning of period.......... 2,364 24,139 20,512 4,588 --------- --------- ---------- ---------- Cash and cash equivalents at end of period................ $ 1,792 $ 45,785 $ 1,792 $ 45,785 ========= ========= ========== ========== <FN> The preceding Notes to Financial Statements as they relate to Ohio Edison Company are an integral part of these statements. </FN> </TABLE> 56
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 September 30, 2003, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for each of the three-month and nine-month periods ended September 30, 2002. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained a reference to the Company's restatement of its previously issued consolidated financial statements for the year ended December 31, 2002 as discussed in Note 1(M) to those consolidated financial statements) dated February 28, 2003, except as to Note 1(M), which is as of August 18, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2003 57
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. RESTATEMENTS As further discussed in Note 1 to the Consolidated Financial Statements, OE restated its consolidated financial statements for the year ended December 31, 2002 and the three months ended March 31, 2003. The revisions reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan. These restatements were completed and reported in the second quarter of 2003. Financial comparisons described below for the three-month and nine month-periods reflect the effect of these restatements. RESULTS OF OPERATIONS Earnings on common stock in the third quarter of 2003 decreased to $80.1 million from $128.6 million in the third quarter of 2002. During the first nine months of 2003, earnings on common stock decreased to $212.9 million from $302.8 million in the same period of 2002. In the first nine months of 2003 earnings on common stock included an after tax credit of $31.7 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $183.2 million in the first nine months of 2003, compared to $308.6 million for the same period of 2002. Results in the third quarter of 2003 were adversely affected by lower revenues due to milder weather and higher operating expenses (principally from additional outage-related work at the nuclear generating plants and increased amortization of the Ohio transition regulatory assets) compared to the same quarter of last year. These adverse effects were partially offset by reduced nuclear fuel expenses as a result of the additional nuclear outage in 2003 and reduced financing costs compared to the third quarter of 2002. In the first nine months of 2003, results were negatively affected by lower revenues from mild weather in the second and third quarters of 2003, which moderated the effect of unusually cold weather earlier in the year. Additional nuclear outage-related work and increased amortization of the Ohio transition regulatory assets were also primary factors contributing to an increase in operating expenses in the first nine months of 2003 from the same period in 2002. Partially offsetting these factors were reduced fuel expense resulting from lower nuclear production and the absence in 2003 of an adjustment recorded in the first quarter of 2002 for low income housing investments. Operating revenues decreased by $38.4 million or 4.7% in the third quarter and $74.3 million or 3.3% in the first nine months of 2003 compared with the same periods in 2002 due to cooler-than-normal temperatures in the second and third quarters, continued sluggishness in the regional economy and increased sales by alternative suppliers. The lower revenues primarily resulted from reduced generation sales revenues, which included all retail customer categories - - residential, commercial and industrial. Kilowatt-hour sales to retail customers declined by 12.9% in the third quarter and 10.5% in the first nine months of 2003 from the same periods of 2002, reducing generation sales revenue by $36.4 million and $97.1 million, respectively. Electric generation services provided to retail customers by alternative suppliers as a percent of total kilowatt-hours delivered in OE's franchise area increased 6.0 percentage points in the third quarter and 7.5 percentage points in the first nine months of 2003 from the corresponding periods last year. Distribution deliveries decreased 5.6% and 1.2% in the third quarter and the first nine months of 2003, respectively, compared with the corresponding periods of 2002. The lower distribution deliveries in the third quarter of 2003 reflected the milder weather in that period compared to the same period last year which reduced residential and commercial usage - the customer groups accounting for most of a $23.1 million reduction in revenues from electricity throughput. In the nine months of 2003, unusually cold weather in early 2003 increased distribution deliveries to commercial customers, providing most of the increase in revenues from distribution throughput compared to the same period in 2002. The third quarter and first nine months of 2003 were both adversely impacted by the continued effects of a sluggish regional economy reducing demand by industrial customers in OE's franchise area. 58
Operating revenues were further reduced in 2003 as a result of the Ohio transition plan incentives provided to customers to promote customer shopping for alternative suppliers - $1.9 million of additional credits in the first nine months of 2003 from the corresponding period of 2002. These reductions in revenues are deferred for future recovery under OE's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers increased by $12.0 million and $24.5 million in the third quarter and the first nine months of 2003, respectively, compared to the same periods of 2002. These results reflect the effect of higher unit prices, partially offset by lower kilowatt-hour sales to the wholesale market due to reduced nuclear generation available for sale to FES. Changes in electric generation sales and distribution deliveries in the third quarter and first nine months of 2003 from the corresponding periods of 2002 are summarized in the following table: Changes in Kilowatt-Hour Sales Three Months Nine Months --------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail............................... (12.9)% (10.5)% Wholesale............................ (9.2)% (14.6)% ------------------------------------------------------------------- Total Electric Generation Sales........ (11.1)% (12.4)% =================================================================== Distribution Deliveries: Residential.......................... (11.2)% (3.2)% Commercial........................... (1.4)% 0.8% Industrial........................... (3.1)% (1.0)% ------------------------------------------------------------------- Total Distribution Deliveries.......... (5.6)% (1.2)% =================================================================== Operating Expenses and Taxes Total operating expenses and taxes increased $22.4 million and $93.2 million in the third quarter and the first nine months of 2003, respectively, from the same periods last year. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes Three Months Nine Months - ----------------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................ $ (1.7) $ (7.9) Purchased power costs........................... (11.8) (6.3) Nuclear operating costs......................... 19.3 87.0 Other operating costs........................... 12.7 25.1 - ------------------------------------------------------------------------ Total operation and maintenance expenses...... 18.5 97.9 Provision for depreciation and amortization..... 30.8 61.9 General taxes................................... (0.4) 4.4 Income taxes.................................... (26.5) (71.0) - ------------------------------------------------------------------------ Net increase in operating expenses and taxes.. $ 22.4 $ 93.2 ======================================================================== Lower fuel costs in the third quarter and first nine months of 2003, compared with the same periods of 2002, resulted from reduced nuclear generation - - down 4.7% and 15.1%, respectively. In the third quarter and first nine months of 2003, the kilowatt-hour purchase requirements were lower than the same periods in 2002 because of reduced electric generation sales - those cost reductions were partially offset by the effect of higher unit costs. Higher nuclear operating costs in the 2003 periods were driven by three nuclear refueling outages in 2003 - Beaver Valley Unit 1 (100% ownership), Beaver Valley Unit 2 (55.62% interest) and the Perry Plant (35.24% ownership) in 2003 compared with one refueling outage at Beaver Valley Unit 2 in 2002. The Beaver Valley Unit 1 and Perry refueling outages earlier in 2003 included additional unplanned work which extended the length of the outages and increased their cost. The increase in other operating costs in the third quarter and first nine months of 2003, compared to the same periods of 2002, primarily reflects higher employee benefit costs and energy delivery costs as a result of storm damage. Charges for depreciation and amortization increased by $30.8 million in the third quarter of 2003 compared to the third quarter of 2002 primarily from three factors - increased amortization of the Ohio transition regulatory assets ($16.6 million), reduced shopping incentive deferrals ($9.0 million) and reduced transition plan regulatory asset deferrals in 2003 ($10.3 million). Partially offsetting these increases were lower charges resulting from the implementation of SFAS 143 ($4.6 million). In the first nine months of 2003, depreciation and amortization increased by $61.9 million compared to the corresponding period of 2002 as a result of the same factors which impacted the third quarter comparison - increased 59
amortization of the Ohio transition regulatory assets ($58.3 million) and reduced transition plan regulatory asset deferrals ($22.5 million) in 2003. Partially offsetting these increases in depreciation and amortization were higher shopping incentive deferrals ($1.9 million) and lower charges resulting from the implementation of SFAS 143 ($15.5 million). General taxes increased in the first nine months of 2003 from the same periods of 2002 principally due to higher kilowatt-hour excise taxes in Ohio. Other Income Other income increased by $15.5 million in the first nine months of 2003 from the same period last year, primarily due to the absence in 2003 of adjustments recorded in the first nine months of 2002 related to OE's low income housing investments. Net Interest Charges Net interest charges continued to trend lower, decreasing by $10.1 million in the third quarter and $26.6 million in the first nine months of 2003 from the same periods last year, reflecting redemptions and refinancings since the third quarter of last year. OE's mandatory debt redemptions totaled $230.2 million during the first nine months of 2003, are expected to result in annualized savings of $19.0 million. Cumulative Effect of Accounting Change Results for the first nine months of 2003 include an after-tax credit to net income of $31.7 million recorded upon the adoption of SFAS 143 in January 2003. OE identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $133.7 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $25.2 million. The asset retirement obligation (ARO) liability at the date of adoption was $297.6 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, OE had recorded decommissioning liabilities of $281 million. Penn expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, Penn recognized a regulatory liability of $10.6 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning. The remaining cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $54.1 million increase to income, or $31.7 million net of income taxes. CAPITAL RESOURCES AND LIQUIDITY OE's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without significantly 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 September 30, 2003, OE had $1.8 million of cash and cash equivalents, compared with $20.5 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided by operating activities during the third quarter and first nine months of 2003, compared with the corresponding periods in 2002 were as follows: Three Months Ended Nine Months Ended September 30, September 30, ---------------------------------------------- Operating Cash Flows 2003 2002 2003 2002 - ------------------------------------------------------------------------------- (In millions) Cash earnings (1).............. $234 $261 $519 $611 Working capital and other...... 320 13 264 224 - ------------------------------------------------------------------------------- Total.......................... $554 $274 $783 $835 - ------------------------------------------------------------------------------- (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. 60
Net cash from operating activities increased $280 million in the third quarter of 2003 due to a $307 million increase in funds from working capital, partially offset by a $27 million decrease in cash earnings. The change in working capital and other primarily reflects lower accounts receivable in the third quarter of 2003 compared with the corresponding change in the third quarter of 2002 ($348 million). A higher tax accrual in the third quarter of 2003, compared to 2002, also contributed $115 million to the increase in working capital. Cash Flows From Financing Activities In the third quarter of 2003, net cash used for financing activities increased to $308 million from $61 million used in the same period last year. The increase resulted from the absence of new financing in 2003 and increased dividends to FirstEnergy. OE had approximately $579.6 million of cash and temporary investments and approximately $184.5 million of short-term indebtedness as of September 30, 2003. Available borrowing capability under bilateral bank facilities totaled $34.0 million as of September 30, 2003. OE had the capability to issue $1.8 billion of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests OE could issue up to $1.6 billion of preferred stock (assuming no additional debt was issued) as of September 30, 2003. In October 2003, FirstEnergy renewed $1 billion of credit facilities (including OE's 364-day $125 million facility and 3-year $125 million facility). Cash Flows From Investing Activities Net cash used for investing activities totaled $247 million in the third quarter of 2003, compared to $191 million for the same period of 2002. The $56 million increase in funds used for investing activities resulted from increases in short-term loans to associated companies. During the fourth quarter of 2003, capital requirements for property additions and capital leases are expected to be about $32 million, including $1 million for nuclear fuel. OE has additional requirements of approximately $17 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse (OE has no ownership interest in this facility). Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI, and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the securities of its electric utility operating companies. Fitch stated that the changes to the long-term ratings were "driven by the high debt leverage of the parent FE. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been vulnerable to unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable Outlook reflects the success of FE's recent common equity offering and management's focus on a relatively conservative integrated utility strategy." On October 27, 2003, Standard & Poors (S&P) stated that the `BBB' corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its utility subsidiaries remain on CreditWatch with negative implications. The ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's concerns regarding the potential impact of the August 14, 2003 blackout investigation on FirstEnergy's deleveraging strategy and its overall efforts to improve its credit profile. At that time, S&P also noted other challenges facing FirstEnergy, including the extended Davis-Besse outage; the recent U.S. District Court ruling regarding the Sammis Plant (see Environmental Matters below); reliability concerns in subsidiary JCP&L's service territory; and FirstEnergy's credibility with regulators and federal officials. S&P further noted several factors that could aid FirstEnergy in resolution of the CreditWatch, including strengthening its balance sheet. FirstEnergy directly addressed this concern through its recently completed common equity offering that raised approximately $935 million in net proceeds, which was used to reduce bank debt. S&P described the equity offering as a "positive credit development" and also noted the recent renewal of FirstEnergy's $1 billion revolver facilities as a "favorable development, as it mitigates liquidity concerns." S&P also indicated that should various ongoing investigations into the causal factors of the August 14, 2003 blackout establish that the blackout resulted 61
from no negligence or breach of compliance standards on FirstEnergy's part, the CreditWatch could be removed and the outlook returned to negative. S&P deemed a "stable" credit outlook unlikely until issues such as the restart of Davis-Besse are resolved and the potential effect of the litigation relating to the Sammis plant (the second trial is scheduled for April 2004) are known. Extension of the Ohio transition plan will be viewed as a positive development and will support an outlook revision to stable. On October 27, 2003, S&P also noted that the ratings on FirstEnergy and its subsidiaries incorporate such strengths as the ability to generate free cash flow, power generation contracted to its transmission and distribution subsidiaries through 2005, and the hedging of its short power position arising from its PLR obligation in Pennsylvania. S&P said that these strengths are offset by slower than anticipated reduction of FirstEnergy debt, remaining volume risks of PLR obligations, the extended outage at Davis-Besse, the unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty in Ohio. S&P also said that it now views FirstEnergy's liquidity position as average, following FirstEnergy's renewal of its $1 billion credit facilities. Other Obligations Obligations not included on OE's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. As of September 30, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $709 million. EQUITY PRICE RISK Included in OE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $180 million and $148 million as of September 30, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $18 million reduction in fair value as of September 30, 2003. OUTLOOK Beginning in 2001, OE's customers were able to select alternative energy suppliers. OE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's Ohio customers elects to obtain power from an alternative supplier, OE reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by the Public Utilities Commission of Ohio (PUCO), Pennsylvania Public Utility Commission and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets declined by $361.4 million during the first nine months of 2003, to $1.6 billion as of September 30, 2003; $10.6 million of the decrease related to the cumulative adjustment related to the adoption of SFAS 143 at Penn and the balance of the reduction resulting from recovery of transition plan regulatory assets. All of the OE Companies' regulatory assets are expected to continue to be recovered under the provisions of their respective transition plan and rate restructuring plan. The OE Companies' regulatory assets are as follows: September 30, December 31, Regulatory Assets 2003 2002 - --------------------------------------------------------- (In millions) OE......................... $1,594.0 $1,848.7 Penn....................... 50.2 156.9 - --------------------------------------------------------- Consolidated Total...... $1,644.2 $2,005.6 ========================================================= As part of OE's Ohio transition plan, OE 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. 62
On October 21, 2003, the Ohio Companies 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 supply and continuing FirstEnergy's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service, including PLR responsibility, for FirstEnergy's Ohio 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 FirstEnergy's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity as discussed above. In order to facilitate supply planning, FirstEnergy has requested that the PUCO rule on this proposal by December 31, 2003. Under the proposed plan, OE is requesting: o Extension of the transition cost amortization period for OE from 2006 to 2007; o Deferral of new regulatory assets and deferral of interest costs on the shopping incentive and other new deferrals; o Ability to initiate a request to increase generation rates only under certain limited conditions. As a result of the Ohio Companies' October 21 filing, the PUCO entered an order on October 28, 2003 setting forth the discovery schedule related to the application with hearings scheduled to begin December 3, 2003. Environmental Matters OE believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from OE's Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2 - Environmental Matters). OE continues to evaluate its compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. OE cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U. S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act (CAA). The civil complaint against OE and Penn requests installation of "best available control technology" as well as civil penalties of up to $27,500 per day 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 April 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 Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been recorded as of September 30, 2003. 63
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. OE believes it is in compliance with the current SO2 and NOx reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that required compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. The effects of compliance on OE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect our earnings and competitive position to the extent OE competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. OE believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Legal Matters Various lawsuits, claims and proceedings related to OE's normal business operations are pending against it, the most significant of which are described above. SIGNIFICANT ACCOUNTING POLICIES OE prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect OE's financial results. All of the OE Companies' assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. The OE Companies' more significant accounting policies are described below. Regulatory Accounting The OE Companies are subject to regulation that sets the prices (rates) they are permitted to charge their customers based on the costs that the regulatory agencies determine the OE Companies are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio and Pennsylvania, a significant amount of regulatory assets have been recorded - $1.6 billion as of September 30, 2003. OE regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition The OE Companies follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: 64
o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001 plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy is not required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's restructuring 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, "Accounting for the Impairment or Disposal of Long-Lived Assets," the OE Companies periodically evaluate their long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must 65
be recognized in the financial statements. If impairment other than of a temporary nature has occurred, the OE Companies recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). RECENTLY ISSUED ACCOUNTING STANDARDS FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". This Interpretation requires the consolidation of a variable interest entity (VIE) by an enterprise if that enterprise either absorbs a majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns as a result of ownership, contractual or other financial interests in the VIE. Currently, entities are generally consolidated by an enterprise that has a controlling financial interest through ownership of a majority voting interest in the entity. FIN 46 defines a VIE as an entity in which equity investors do not have the characteristics of a controlling financial interest nor have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. VIE's created after January 31, 2003, are immediately subject to the provisions of FIN 46. The FASB recently deferred implementation of FIN 46 for VIE's created before February 1, 2003, until the first reporting period ending after December 15, 2003 (OE's quarter ending December 31, 2003.) OE currently has transactions with entities in connection with sale and leaseback arrangements which may fall within the scope of this interpretation and which meet the definition of a VIE in accordance with FIN 46. The Company currently believes that it will consolidate the PNBV Capital Trust, which issued equity and notes to fund the acquisition of a portion of the collateralized lease bonds that had been issued in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by the PNBV Trust. Ownership of the trust includes a three-percent equity interest by a nonaffiliated third party and a three-percent equity interest by OES Ventures, a wholly owned subsidiary of OE. Consolidation of the trust as of December 31, 2002 would have changed the PNBV trust investment of $389 million to an investment in collateralized lease bonds of $401 million. The increase in $12 million would have represented the minority interest in the total assets of the trust. In addition to the PNBV Capital Trust discussed above, the Company is evaluating its interest in the owner trusts that acquired certain interests in the Perry Plant and Beaver Valley Unit 2. OE has not completed its evaluation to determine if it would be the primary beneficiary and therefore required to consolidate these trusts. The FASB continues to provide additional guidance on implementing FIN 46 and recently proposed modifications and clarifications with a comment period ending December 1, 2003. As this guidance is finalized, OE will continue to assess the accounting and disclosure impact of FIN 46 with respect to the VIE's discussed above as well as other potential VIE's. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. Upon adoption of SFAS 150, on July 1, 2003, OE reclassified as debt the preferred stock of consolidated subsidiaries subject to mandatory redemption having carrying values of approximately $13.5 million as of September 30, 2003. Prior to the adoption of SFAS 150, subsidiary preferred dividends on OE's Consolidated Statements of Income were included in net interest charges. Therefore, the application of SFAS 150 did not require the reclassification of such preferred dividends to net interest charges. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus on Issue No. 01-08, regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if: (1) it identifies specific property, plant or equipment (explicitly or implicitly); and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus is to be applied prospectively to arrangements committed to, modified or acquired through a business combination. The adoption of this consensus as of July 1, 2003 did not impact OE's financial statements. 66
<TABLE> <CAPTION> THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ------------------------- 2003 2002 2003 2002 -------- -------- ---------- ---------- Restated Restated (See Note 1) (See Note 1) (In thousands) <S> <C> <C> <C> <C> OPERATING REVENUES........................................ $496,699 $538,879 $1,328,603 $1,435,030 -------- -------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel................................................... 5,536 15,809 31,580 48,167 Purchased power........................................ 139,661 140,357 407,261 398,251 Nuclear operating costs................................ 67,449 49,093 190,028 143,695 Other operating costs.................................. 65,230 73,586 191,525 192,686 -------- -------- ---------- ---------- Total operation and maintenance expenses........... 277,876 278,845 820,394 782,799 Provision for depreciation and amortization............ 42,443 47,646 147,111 153,250 General taxes.......................................... 37,689 40,771 114,741 116,010 Income taxes........................................... 38,719 51,705 47,827 98,459 -------- -------- ---------- ---------- Total operating expenses and taxes................. 396,727 418,967 1,130,073 1,150,518 -------- -------- ---------- ---------- OPERATING INCOME.......................................... 99,972 119,912 198,530 284,512 OTHER INCOME.............................................. 6,467 5,562 15,892 14,159 -------- -------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES........................ 106,439 125,474 214,422 298,671 -------- -------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt............................. 38,130 44,441 118,069 136,808 Allowance for borrowed funds used during construction.. (1,920) (1,155) (5,724) (2,651) Other interest expense................................. 163 1,727 199 1,073 Subsidiaries' preferred stock dividend requirements.... 2,250 2,250 9,450 6,650 -------- -------- ---------- ---------- Net interest charges............................... 38,623 47,263 121,994 141,880 -------- -------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ................................................... 67,816 78,211 92,428 156,791 Cumulative effect of accounting change (net of income taxes of $30,168,000) (Note 5)......................... -- -- 42,378 -- -------- -------- ---------- ---------- NET INCOME................................................ 67,816 78,211 134,806 156,791 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 1,865 3,149 2,970 12,759 -------- -------- ---------- ---------- EARNINGS ON COMMON STOCK.................................. $ 65,951 $ 75,062 $ 131,836 $ 144,032 ======== ======== ========== ========== <FN> The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements. </FN> </TABLE> 67
<TABLE> <CAPTION> THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (See Note 1) (In thousands) ASSETS ------ <S> <C> <C> UTILITY PLANT: In service................................................................ $4,208,873 $4,045,465 Less-Accumulated provision for depreciation............................... 1,892,945 1,824,884 ---------- ---------- 2,315,928 2,220,581 ---------- ---------- Construction work in progress- Electric plant.......................................................... 137,096 153,104 Nuclear fuel............................................................ 28,554 45,354 ---------- ---------- 165,650 198,458 ---------- ---------- 2,481,578 2,419,039 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust................................................ 385,945 435,907 Nuclear plant decommissioning trusts...................................... 279,074 230,527 Long-term notes receivable from associated companies...................... 108,192 102,978 Other..................................................................... 20,805 21,004 ---------- ---------- 794,016 790,416 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 159 30,382 Receivables- Customers............................................................... 9,977 11,317 Associated companies.................................................... 39,680 74,002 Other (less accumulated provisions of $1,000,000 and $1,015,000, respectively, for uncollectible accounts)............................. 83,577 134,375 Notes receivable from associated companies................................ 587 447 Materials and supplies, at average cost- Owned................................................................... 16,724 18,293 Under consignment....................................................... 31,016 38,094 Prepayments and other..................................................... 3,503 4,217 ---------- ---------- 185,223 311,127 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 1,138,236 1,191,804 Goodwill.................................................................. 1,693,629 1,693,629 Property taxes............................................................ 79,430 79,430 Other..................................................................... 23,980 24,798 ---------- ---------- 2,935,275 2,989,661 ---------- ---------- $6,396,092 $6,510,243 ========== ========== </TABLE> 68
<TABLE> <CAPTION> THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (See Note 1) (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ <S> <C> <C> CAPITALIZATION: Common stockholder's equity- Common stock, without par value, authorized 105,000,000 shares- 79,590,689 shares outstanding......................................... $ 981,962 $ 981,962 Accumulated other comprehensive loss.................................... (17,061) (44,284) Retained earnings....................................................... 394,162 262,323 ---------- ---------- Total common stockholder's equity................................... 1,359,063 1,200,001 Preferred stock- Not subject to mandatory redemption..................................... 96,404 96,404 Subject to mandatory redemption (Note 5)................................ -- 5,021 Company obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures (Note 5) ............................................................... -- 100,000 Long-term debt and other long-term obligations- Preferred stock subject to mandatory redemption (Note 5)................ 4,016 -- Company-obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company subordinated debentures (Note 5)......... .................................................... 100,000 -- Other................................................................... 1,773,797 1,975,001 ---------- ---------- 3,333,280 3,376,427 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock...................... 438,289 388,190 Accounts payable- Associated companies.................................................... 242,433 267,664 Other................................................................... 5,762 14,583 Notes payable to associated companies..................................... 215,093 288,583 Accrued taxes............................................................. 160,026 126,261 Accrued interest.......................................................... 56,195 51,767 Lease market valuation liability.......................................... 60,000 60,000 Other..................................................................... 46,865 64,624 ---------- ---------- 1,224,663 1,261,672 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 494,638 407,297 Accumulated deferred investment tax credits............................... 67,198 70,803 Nuclear plant decommissioning costs....................................... -- 242,511 Asset retirement obligation............................................... 250,687 -- Retirement benefits....................................................... 116,308 171,968 Lease market valuation liability.......................................... 743,700 788,800 Other..................................................................... 165,618 190,765 ---------- ---------- 1,838,149 1,872,144 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $6,396,092 $6,510,243 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these balance sheets. </FN> </TABLE> 69
<TABLE> <CAPTION> THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ----------------------- ------------------------- 2003 2002 2003 2002 --------- --------- ---------- ---------- Restated Restated (See Note 1) (See Note 1) (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 67,816 $ 78,211 $ 134,806 $ 156,791 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 42,443 47,646 147,111 153,250 Nuclear fuel and capital lease amortization........ 4,178 5,037 12,217 15,821 Other amortization................................. (7,911) (3,937) (12,933) (12,104) Deferred operating lease costs, net................ (36,167) (25,220) (77,992) (76,888) Deferred income taxes, net......................... 14,847 676 48,784 3,582 Amortization of investment tax credits............. (1,202) (1,159) (3,605) (3,472) Accrued retirement benefit obligations............. 26,453 2,437 10,566 5,151 Accrued compensation, net.......................... 257 3,386 (4,056) 2,422 Cumulative effect of accounting charge (Note 5).... -- -- (72,546) -- Receivables........................................ 234,672 3,274 86,460 (36,683) Materials and supplies............................. (2,164) (1,786) 8,647 (4,992) Accounts payable................................... (235,048) (23,141) (55,802) 3,238 Accrued taxes...................................... 46,327 30,546 33,765 43,221 Accrued interest................................... 7,996 2,726 4,428 2,388 Prepayments and other current assets............... (479) (1,466) 714 28,145 Other.............................................. (9,831) (3,831) 20,897 (35,997) --------- --------- ---------- ---------- Net cash provided from operating activities...... 152,187 113,399 281,461 243,873 --------- --------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... -- 77,505 -- 77,505 Short-term borrowings, net........................... -- 162,858 -- 189,521 Equity contributions from parent..................... -- 50,000 -- 50,000 Redemptions and Repayments- Preferred stock...................................... (1,000) (47,017) (1,093) (147,017) Long-term debt....................................... (256) (309,189) (146,321) (309,379) Short-term borrowings, net........................... (123,711) -- (73,490) -- Dividend Payments- Preferred stock...................................... (1,864) (2,283) (5,594) (10,668) --------- --------- ---------- ---------- Net cash used for financing activities........... (126,831) (68,126) (226,498) (150,038) --------- --------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... (29,620) (40,545) (91,643) (102,467) Notes receivable from associated companies, net........ (5,574) -- (5,354) 205 Capital trust investments.............................. 30,891 10,325 49,962 37,719 Contributions to nuclear decommissioning trusts ....... (14,512) (7,256) (21,768) (21,768) Other.................................................. (6,541) 119 (16,383) 386 --------- --------- ---------- ---------- Net cash used for investing activities........... (25,356) (37,357) (85,186) (85,925) --------- --------- ---------- ---------- Net increase (decrease) in cash and cash equivalents...... -- 7,916 (30,223) 7,910 Cash and cash equivalents at beginning of period.......... 159 290 30,382 296 --------- --------- ---------- ---------- Cash and cash equivalents at end of period................ $ 159 $ 8,206 $ 159 $ 8,206 ========= ========= ========== ========== <FN> The preceding Notes to Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements. </FN> </TABLE> 70
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 September 30, 2003, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for each of the three-month and nine-month periods ended September 30, 2002. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common 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 goodwill in 2002 as discussed in Note 1(D) to those consolidated financial statements and the Company's restatement of its previously issued consolidated financial statements as of December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002 as discussed in Note 1(M) to those consolidated financial statements) dated August 18, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2003 71
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. RESTATEMENTS As further discussed in Note 1 to the Consolidated Financial Statements, CEI restated its consolidated financial statements for the three years ended December 31, 2002 and the three months ended March 31, 2003 to reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. These restatements were completed and reported in the second quarter of 2003. Financial comparisons described below for the three-month and nine month-periods reflect the effect of these restatements. RESULTS OF OPERATIONS Earnings on common stock in the third quarter of 2003 decreased to $66.0 million from $75.1 million in the third quarter of 2002. Earnings on common stock in the first nine months of 2003 included an after-tax credit of $42.4 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $92.4 million in the first nine months of 2003, compared to $156.8 million for the same period of 2002. Reduced earnings in both periods resulted principally from lower revenues in 2003 compared to 2002 due to milder weather. Operating revenues decreased by $42.2 million or 7.8% in the third quarter and $106.4 million or 7.4% in the first nine months of 2003 from the same periods of 2002 reflecting milder weather in the third quarter and increased sales by alternative suppliers. Kilowatt-hour sales to retail customers declined 28.8% in the third quarter and 17.2% in the first nine months of 2003 from the corresponding periods of 2002, reducing generation sales revenue by $21.5 million and $50.1 million, respectively. Milder weather in the third quarter of 2003 reduced sales to residential and commercial customers. Kilowatt-hour sales of electricity by alternative suppliers in CEI's franchise area increased by 12.5 percentage points in the third quarter and 11.2 percentage points in the first nine months of 2003 from the corresponding periods last year. Distribution deliveries were lower by 12.6% in the third quarter and 1.4% in the first nine months of 2003 compared to the corresponding periods of 2002. The reduction in distribution deliveries, partially offset by the effect of higher unit prices, resulted in a $7.4 million and $3.2 million reduction in revenues from electricity throughput in the third quarter and first nine months of 2003, respectively, compared to the same periods last year. Lower temperatures in the third quarter of 2003 reduced air-conditioning loads of residential and commercial customers for that period while residential and commercial loads benefited from cooler temperatures in the first quarter of 2003 which moderated the distribution delivery reductions in the first nine months of 2003 as compared to 2002. Further decreasing operating revenues were Ohio transition plan incentives, provided to customers to encourage switching to alternative energy providers - $13.7 million of additional credits in the third quarter and $24.2 million of additional credits in the first nine months of 2003 compared with the corresponding periods of 2002. These revenue reductions are deferred for future recovery under CEI's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers (primarily FES) decreased by $1.1 million in the third quarter and $22.6 million in the first nine months of 2003 compared with the same periods of 2002. The lower sales resulted from reductions in available nuclear generation of 6.6% in the third quarter and 22.3% in the first nine months of 2003 compared to the corresponding periods of 2002. Available generation decreased due to the extended outage of Davis-Besse and generating capacity removed from service due to additional nuclear refueling activities in 2003 compared to 2002. Changes in electric generation sales and distribution deliveries in the third quarter and first nine months of 2003 from the corresponding periods of 2002 are summarized in the following table: 72
Changes in Kilowatt-hour Sales Three Months Nine Months - --------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (28.8)% (17.2)% Wholesale............................. (4.4)% (13.7)% - ------------------------------------------------------------------- Total Electric Generation Sales......... (17.8)% (15.5)% =================================================================== Distribution Deliveries: Residential........................... (10.4)% (1.1)% Commercial............................ (1.5)% 1.2% Industrial............................ (19.9)% (3.1)% - ------------------------------------------------------------------- Total Distribution Deliveries (12.6)% (1.4)% =================================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $22.2 million in the third quarter and $20.4 million in the first nine months of 2003 from the same periods of 2002. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes Three Months Nine Months - ----------------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................ $(10.3) $(16.6) Purchased power costs........................... (0.7) 9.0 Nuclear operating costs......................... 18.4 46.3 Other operating costs........................... (8.4) (1.1) - -------------------------------------------------------------------------- Total operation and maintenance expenses...... (1.0) 37.6 Provision for depreciation and amortization..... (5.2) (6.1) General taxes................................... (3.0) (1.3) Income taxes.................................... (13.0) (50.6) - -------------------------------------------------------------------------- Net decrease in operating expenses and taxes.. $(22.2) $(20.4) ========================================================================== Lower fuel costs in the third quarter and first nine months of 2003, compared with the same periods of 2002 resulted from reduced nuclear generation. Higher purchased power costs primarily reflect increased unit costs in the first nine months of 2003 compared to the corresponding period of 2002. Increased nuclear costs resulted from incremental costs associated with the extended Davis-Besse outage, unplanned work performed during the Perry Plant 56-day nuclear refueling outage (44.85% ownership) in the second quarter of 2003, and the Beaver Valley Unit 2 28-day refueling outage (24.47% ownership) in the third quarter of 2003, compared with the 24-day refueling outage at Beaver Valley Unit 2 in the first quarter of 2002. The decrease in depreciation and amortization charges in the third quarter of 2003, compared with the third quarter of 2002 was primarily attributable to several factors - increased amortization of regulatory assets being recovered under CEI's transition plan ($5.5 million) and recognition of depreciation on three fossil plants ($7.2 million) which had been held pending sale in the second quarter of 2002 but were subsequently retained by FirstEnergy in the fourth quarter of 2002. Substantially offsetting these factors were higher shopping incentive deferrals ($13.7 million) and lower charges resulting from the implementation of SFAS 143 ($2.9 million). The decrease of $6.1 million in depreciation and amortization charges in the first nine months of 2003, compared with the same period of 2002 reflected the same factors affecting the third quarter of 2003 - decreases due to higher shopping incentive deferrals ($24.2 million) and lower charges from the SFAS 143 implementation ($10.7 million) being partially offset by increases in CEI's transition plan amortization ($13.6 million) and recognition of depreciation on the fossil plants ($21 million). Net Interest Charges Net interest charges continued to trend lower, decreasing by $8.6 million in the third quarter and $19.9 million in the first nine months of 2003 from the same periods last year, reflecting redemption and refinancing activities. CEI's redemption and repricing activities during the first nine months of 2003 totaled $116 million and $113 million, respectively, and are expected to result in annualized savings of approximately $9 million. Cumulative Effect of Accounting Changes Results for the first nine months of 2003 include an after-tax credit to net income of $42.4 million recorded by CEI upon adoption of SFAS 143 in January of 2003. CEI identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $49.9 million were recorded as part of the carrying amount of the related long-lived asset, offset by 73
accumulated depreciation of $6.8 million. The asset retirement obligation liability at the date of adoption was $238.3 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, CEI had recorded decommissioning liabilities of $239.7 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $72.5 million increase to income, or $42.4 million net of income taxes. Preferred Stock Dividend Requirements Preferred stock dividend requirements decreased $9.8 million in the first nine months of 2003, compared to the same period last year, principally due to optional redemptions of preferred stock in 2002. CAPITAL RESOURCES AND LIQUIDITY CEI's cash requirements in the fourth quarter of 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without significantly 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 September 30, 2003, CEI had $0.2 million of cash and cash equivalents, compared with $30.4 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided by operating activities during the third quarter and first nine months of 2003, compared with the corresponding periods in 2002 were as follows: Three Months Ended Nine Months Ended September 30, September 30, ------------------------------------------- Operating Cash Flows 2003 2002 2003 2002 ------------------------------------------------------------------------ (In millions) Cash earnings (1).......... $111 $107 $182 $245 Working capital and other.. 41 6 99 (1) ------------------------------------------------------------------------ Total...................... $152 $113 $281 $244 ======================================================================== (1)Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. The increase in working capital and other reflected increases of $231 million and $16 million in changes in accounts receivable and accrued tax liabilities, respectively, for the third quarter 2003 as compared to the third quarter of 2002 changes which were partially offset by a $212 million decrease in accounts payable for those periods. Net cash from operating activities increased $37 million in the first nine months of 2003 compared to the same period in 2002 as a result of a $100 million working capital and other increase partially offset by a $63 million reduction in cash earnings. The largest factor contributing to the working capital and other increase was a $123 million change in accounts receivable while the cash earnings decrease was primarily attributable to higher nuclear operating costs. Cash Flows From Financing Activities In the third quarter and first nine months of 2003, net cash used for financing activities increased $59 million and $76 million, respectively from the corresponding periods of 2002. The increase in funds used for financing activities primarily reflected higher repayments of short-term borrowings with no new financings in 2003 compared to lower net repayments on long-term debt in 2002. CEI had about $0.7 million of cash and temporary investments and approximately $215.1 million of short-term indebtedness as of September 30, 2003. CEI had the capability to issue $588.0 million of additional first mortgage bonds on the basis of property additions and retired bonds. CEI has no restrictions on the issuance of preferred stock. 74
Cash Flows From Investing Activities Net cash used for investing activities decreased $12 million in the third quarter of 2003 from the same quarter of 2002 due to a change in the Shippingport Capital Trust investment and lower capital expenditures in 2003. During the fourth quarter of 2003, capital requirements for property additions and capital leases are expected to be about $26 million. CEI has no sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. On November 13, 2003, FirstEnergy announced that it had reached an agreement with NRG covering the settlement of its claims resulting from the uncompleted sale of four power plants to NRG, three of which were CEI generating plants (Ashtabula, Eastlake and Lakeshore). Under the agreement FirstEnergy would receive an estimated settlement for the four plants of approximately $198 million in the form of cash (12%), notes (15.2%) and common stock (72.8%). The agreement is subject to FERC authorization and U.S. Bankruptcy Court approval since NRG and certain of its subsidiaries filed for voluntary bankruptcy in May 2003. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI, and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the securities of its electric utility operating companies. Fitch stated that the changes to the long-term debt ratings were "driven by the high debt leverage of the parent FE. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been vulnerable to unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable Outlook reflects the success of FE's recent common equity offering and management's focus on a relatively conservative integrated utility strategy." On October 27, 2003, Standard & Poors (S&P) stated that the `BBB' corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its utility subsidiaries remain on CreditWatch with negative implications. The ratings were placed on CreditWatch on August 18, 2003, and reflect the S&P's concerns regarding the potential impact of the August 14, 2003 blackout investigation on FirstEnergy's deleveraging strategy and its overall efforts to improve its credit profile. At that time, S&P also noted other challenges facing FirstEnergy, including the extended Davis-Besse outage; the recent U.S. District Court ruling regarding the Sammis Plant; reliability concerns in subsidiary JCP&L's service territory; and FirstEnergy's credibility with regulators and federal officials. S&P further noted several factors that could aid FirstEnergy in resolution of the CreditWatch, including strengthening its balance sheet. FirstEnergy directly addressed this concern through its recently completed common equity offering that raised approximately $935 million in net proceeds, which was used to reduce bank debt. S&P described the equity offering as a "positive credit development" and also noted the recent renewal of FirstEnergy's $1 billion revolver facilities as a "favorable development, as it mitigates liquidity concerns." S&P also indicated that should various ongoing investigations into the causal factors of the August 14, 2003 blackout establish that the blackout resulted from no negligence or breach of compliance standards on FirstEnergy's part, the CreditWatch could be removed and the outlook returned to negative. S&P deemed a "stable" credit outlook unlikely until issues such as the restart of Davis-Besse are resolved and the potential effect of the litigation relating to the Sammis plant (the second trial is scheduled for April 2004) are known. Extension of the Ohio transition plan will be viewed as a positive development and will support an outlook revision to stable. On October 27, 2003, S&P also noted that the ratings on FirstEnergy and its subsidiaries incorporate such strengths as the ability to generate free cash flow, power generation contracted to its transmission and distribution subsidiaries through 2005, and the hedging of its short power position arising from its PLR obligation in Pennsylvania. S&P said that these strengths are offset by slower than anticipated reduction of FirstEnergy debt, remaining volume risks of PLR obligations, the extended outage at Davis-Besse, the unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty in Ohio. S&P also said that it now views FirstEnergy's liquidity position as average, following FirstEnergy's renewal of its $1 billion credit facilities. 75
Other Obligations Obligations not included on CEI's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of September 30, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $131 million. CEI sells substantially all of its retail customer receivables, which provided $133 million of off-balance sheet financing as of September 30, 2003. EQUITY PRICE RISK Included in CEI's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $158 million and $119 million as of September 30, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $16 million reduction in fair value as of September 30, 2003. OUTLOOK Beginning in 2001, CEI's customers were able to select alternative energy suppliers. CEI continues to deliver power to residential homes and businesses through its existing distribution systems, which remain regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio CEI has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of CEI's customers elects to obtain power from an alternative supplier, CEI reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. CEI has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by the PUCO and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets decreased by $53.6 million for the first nine months of 2003, to $1,138.2 million as of September 30, 2003. All of CEI's regulatory assets are expected to continue to be recovered under the provisions of its transition plan. As part of CEI's Ohio transition plan CEI is obligated to supply electricity to customers who do not choose an alternative supplier. CEI is also required to provide 400 megawatts (MW) of low cost supply to unaffiliated alternative suppliers 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 Companies 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 supply and continuing FirstEnergy's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service, including PLR responsibility, for FirstEnergy's Ohio 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 FirstEnergy's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity as discussed above. In order to facilitate supply planning, FirstEnergy has requested that the PUCO rule on this proposal by December 31, 2003. Under the proposed plan, CEI is requesting: 76
o Extension of the transition cost amortization period for CEI from 2008 to 2009; o Deferral of new regulatory assets and deferral of interest costs on the shopping incentive and other new deferrals; o Ability to initiate a request to increase generation rates only under certain limited conditions. As a result of the Ohio Companies' October 21 filing, the PUCO entered an order on October 28, 2003 setting forth the discovery schedule related to the application with hearings scheduled to begin December 3, 2003. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FirstEnergy is also accelerating maintenance work that had been planned for future refueling and maintenance outages. Testing of the bottom of the reactor for leaks was completed in October 2003 and no indication of leakage was discovered. FirstEnergy is installing a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FirstEnergy anticipates that the unit will be ready for restart in the fall of 2003. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed FirstEnergy's plans to reduce post-merger debt levels FirstEnergy believes such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). Incremental costs associated with the extended Davis-Besse outage (CEI's share - 51.38%) for the third quarter and first nine months of 2003 and 2002 were as follows: Three Months Ended Nine Months Ended Costs of Davis-Besse Extended Outage September 30, September 30 - -------------------------------------------------------------------------------- 2003 2002 2003 2002 ---- ---- ---- ---- (In millions) Incremental Pre-Tax Expense Replacement power................ $54.9 $50.9 $148.4 $ 84.5 Maintenance...................... 17.5 39.8 75.7 54.1 - ------------------------------------------------------------------------------- Total........................ $72.4 $90.7 $224.1 $138.6 =============================================================================== Capital Expenditures............... $10.9 $27.4 $ 13.3 $ 39.4 =============================================================================== It is anticipated that an additional $14 million in maintenance costs will be expended over the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month during the remaining period of the outage. FirstEnergy has hedged the on-peak replacement energy supply for Davis-Besse for the expected length of the outage. If there are significant delays in the NRC approval process, substantial replacement power costs will continue to be incurred, which will continue to have an adverse effect on CEI's cash flows and results of operations. Environmental Matters CEI believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from its generating facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2 - Environmental Matters). CEI continues to evaluate its compliance plans and other compliance options. 77
Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. CEI cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. CEI believes it is in compliance with the current SO2 and NOx reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that required compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at CEI's Ohio facilities by May 31, 2004. CEI has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2003, based on estimates of the total costs of cleanup, CEI's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. CEI's total accrued liabilities were approximately $2.5 million as of September 30, 2003. The effects of compliance on CEI with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect its earnings and competitive position to the extent CEI competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. CEI believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Legal Matters Various lawsuits, claims and proceedings related to CEI's normal business operations are pending against CEI, the most significant of which are described above. SIGNIFICANT ACCOUNTING POLICIES CEI prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect CEI's financial results. All of CEI's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. CEI's more significant accounting policies are described below. Regulatory Accounting CEI is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine CEI is permitted to recover. At times, regulators permit the future recovery through 78 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 - $1,138.2 million as of September 30, 2003. CEI regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition CEI follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension and OPEB benefits are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy is not required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's restructuring 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. 79
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, "Accounting for the Impairment or Disposal of Long-Lived Assets," CEI periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset, is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment, other than of a temporary nature, has occurred, CEI recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, CEI evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were 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 evaluation of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of September 30, 2003, CEI had approximately $1.7 billion of goodwill. RECENTLY ISSUED ACCOUNTING STANDARDS FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". This Interpretation requires the consolidation of a variable interest entity (VIE) by an enterprise if that enterprise either absorbs a majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns as a result of ownership, contractual or other financial interests in the VIE. Currently, entities are generally consolidated by an enterprise that has a controlling financial interest through ownership of a majority voting interest in the entity. FIN 46 defines a VIE as an entity in which equity investors do not have the characteristics of a controlling financial interest nor have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. VIE's created after January 31, 2003, are immediately subject to the provisions of FIN 46. The FASB recently deferred implementation of FIN 46 for VIE's created before February 1, 2003, until the first reporting period ending after December 15, 2003 (CEI's quarter ending December 31, 2003.) CEI currently has transactions with entities in connection with sale and leaseback arrangements which may fall within the scope of this interpretation and which meet the definition of a VIE in accordance with FIN 46. One such entity is the Shippingport Capital Trust which acquired all of the lease obligation bonds issued in connection with the sale and leaseback in 1987 of interests in the Bruce Mansfield Plant held by CEI and TE, an affiliated company. The equity ownership of this trust includes a 0.34% interest held by Toledo Edison Capital Corporation, an affiliated company, and a 4.85% interest held by unaffiliated third parties. The assets and liabilities of the trust are currently included on a proportionate basis in the financial statements of CEI and TE. Adoption of FIN 46 may result in reporting all of the trust assets and liabilities on the books of CEI. CEI is also evaluating its interests in the owner trusts that acquired the interests in the Bruce Mansfield Plant and Beaver Valley Unit 2. CEI has not completed its evaluation to determine if it would be the primary beneficiary and therefore required to consolidate these trusts. As described in Note 1, CEI's consolidated financial statements include a subsidiary trust that sold trust-preferred securities in which CEI is not the primary beneficiary. Pending further guidance from the FASB that would indicate otherwise, this entity may not be consolidated in CEI's financial statements as of December 31, 2003. The deconsolidation would result in an increase in total assets and liabilities of approximately $3.1 million for the investment in the trust. The FASB continues to provide additional guidance on implementing FIN 46 and recently proposed modifications and clarifications with a comment period ending December 1, 2003. As this guidance is finalized, CEI will 80
continue to assess the accounting and disclosure impact of FIN 46 with respect to the VIE's discussed above as well as other potential VIE's. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the beginning of the first interim period beginning after June 15, 2003 (CEI's third quarter of 2003) for all other financial instruments. Upon adoption of SFAS 150, effective July 1, 2003, CEI reclassified as debt the preferred stock subject to mandatory redemption with a carrying value of approximately $4.0 million as of September 30, 2003. Company-obligated mandatorily redeemable preferred securities of $100 million were also reclassified and included in long-term debt as of September 30, 2003. As required by SFAS 150, the preferred securities subject to mandatory redemption were not restated as long-term debt on the December 31, 2002 balance sheet. Dividends on preferred stock subject to mandatory redemption on CEI's Consolidated Statements of Income, which were not included in net interest charges prior to the adoption of SFAS 150, are now included in net interest charges for the three months ended September 30, 2003. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus on Issue No. 01-08, regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus is to be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. The adoption of this consensus as of July 1, 2003 did not impact CEI's financial statements. 81
<TABLE> <CAPTION> THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2003 2002 2003 2002 -------- -------- -------- -------- Restated Restated (See Note 1) (See Note 1) (In thousands) <S> <C> <C> <C> <C> OPERATING REVENUES........................................ $260,190 $269,857 $708,000 $772,731 -------- -------- -------- -------- OPERATING EXPENSES AND TAXES: Fuel................................................... 2,940 9,524 18,364 30,342 Purchased power........................................ 81,795 85,329 230,271 247,085 Nuclear operating costs................................ 64,681 61,149 195,877 178,939 Other operating costs.................................. 39,692 38,902 106,026 97,281 -------- -------- -------- -------- Total operation and maintenance expenses........... 189,108 194,904 550,538 553,647 Provision for depreciation and amortization............ 36,142 41,813 106,460 116,929 General taxes.......................................... 14,305 14,061 43,279 41,258 Income taxes (benefit)................................. 2,432 892 (13,877) 4,373 -------- -------- -------- -------- Total operating expenses and taxes................. 241,987 251,670 686,400 716,207 -------- -------- -------- -------- OPERATING INCOME.......................................... 18,203 18,187 21,600 56,524 OTHER INCOME.............................................. 5,768 4,033 12,644 12,119 -------- -------- -------- -------- INCOME BEFORE NET INTEREST CHARGES........................ 23,971 22,220 34,244 68,643 -------- -------- -------- -------- NET INTEREST CHARGES: Interest on long-term debt............................. 9,039 14,611 32,485 46,084 Allowance for borrowed funds used during construction.. (1,458) (611) (3,948) (1,421) Other interest expense (credit)........................ 639 463 1,068 (632) -------- -------- -------- -------- Net interest charges............................... 8,220 14,463 29,605 44,031 -------- -------- -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ................................................... 15,751 7,757 4,639 24,612 Cumulative effect of accounting change (net of income taxes of $18,201,000) (Note 5)......................... -- -- 25,550 -- -------- -------- -------- -------- NET INCOME................................................ 15,751 7,757 30,189 24,612 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,211 2,211 6,627 9,145 -------- -------- -------- -------- EARNINGS ON COMMON STOCK.................................. $ 13,540 $ 5,546 $ 23,562 $ 15,467 ======== ======== ======== ======== <FN> The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. </FN> 82 </TABLE>
<TABLE> <CAPTION> THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (See Note 1) (In thousands) ASSETS ------ <S> <C> <C> UTILITY PLANT: In service................................................................ $1,697,909 $1,600,860 Less--Accumulated provision for depreciation.............................. 747,456 706,772 ---------- ---------- 950,453 894,088 ---------- ---------- Construction work in progress- Electric plant.......................................................... 106,471 104,091 Nuclear fuel............................................................ 26,057 33,650 ---------- ---------- 132,528 137,741 ---------- ---------- 1,082,981 1,031,829 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Shippingport Capital Trust................................................ 219,973 240,963 Nuclear plant decommissioning trusts...................................... 214,395 174,514 Long-term notes receivable from associated companies...................... 163,638 162,159 Other..................................................................... 75,281 2,236 ---------- ---------- 673,287 579,872 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 11,275 20,688 Receivables- Customers............................................................... 4,339 4,711 Associated companies.................................................... 33,496 55,245 Other................................................................... 20,842 6,778 Notes receivable from associated companies................................ 9,079 1,957 Materials and supplies, at average cost- Owned................................................................... 12,563 13,631 Under consignment....................................................... 20,232 22,997 Prepayments and other..................................................... 9,172 3,455 ---------- ---------- 120,998 129,462 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 516,284 578,243 Goodwill.................................................................. 504,522 504,522 Property taxes............................................................ 23,429 23,429 Other..................................................................... 16,106 14,257 ---------- ---------- 1,060,341 1,120,451 ---------- ---------- $2,937,607 $2,861,614 ========== ========== </TABLE> 83
<TABLE> <CAPTION> THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ----------- ------------ (See Note 1) (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ <S> <C> <C> CAPITALIZATION: Common stockholder's equity- Common stock, $5 par value, authorized 60,000,000 shares - 39,133,887 shares outstanding......................................... $ 195,670 $ 195,670 Other paid-in capital................................................... 428,559 428,559 Accumulated other comprehensive loss.................................... (4,453) (20,012) Retained earnings....................................................... 100,539 76,978 ---------- ---------- Total common stockholder's equity................................... 720,315 681,195 Preferred stock not subject to mandatory redemption....................... 126,000 126,000 Long-term debt............................................................ 285,565 557,265 ---------- ---------- 1,131,880 1,364,460 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 341,650 189,355 Accounts payable- Associated companies.................................................... 120,256 171,862 Other................................................................... 3,212 9,338 Notes payable- Associated companies.................................................... 333,695 149,653 Banks................................................................... 70,000 -- Accrued taxes............................................................. 50,958 34,676 Accrued interest.......................................................... 14,012 16,377 Lease market valuation liability.......................................... 24,600 24,600 Other..................................................................... 26,543 57,462 ---------- ---------- 984,926 653,323 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 188,651 158,279 Accumulated deferred investment tax credits............................... 27,714 29,255 Nuclear plant decommissioning costs....................................... -- 179,587 Asset retirement obligation............................................... 178,847 -- Retirement benefits....................................................... 60,105 82,553 Lease market valuation liability.......................................... 298,750 317,200 Other..................................................................... 66,734 76,957 ---------- ---------- 820,801 843,831 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $2,937,607 $2,861,614 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets. </FN> </TABLE> 84
<TABLE> <CAPTION> THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2003 2002 2003 2002 -------- -------- -------- -------- Restated Restated (See Note 1) (See Note 1) (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 15,751 $ 7,757 $ 30,189 $ 24,612 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 36,142 41,813 106,460 116,929 Nuclear fuel and capital lease amortization........ 2,182 2,765 6,770 9,009 Deferred operating lease costs, net................ (4,212) 2,755 (39,671) (37,999) Deferred income taxes, net......................... (11,570) (11,266) 5,421 (14,346) Amortization of investment tax credits............. (514) (454) (1,542) (1,507) Accrued retirement benefit obligation.............. 7,800 928 5,467 1,710 Accrued compensation, net.......................... (608) 912 (2,754) 912 Cumulative effect of accounting change............. -- -- (43,751) -- Receivables........................................ 25,437 22,359 8,058 15,219 Materials and supplies............................. (1,317) (2,150) 3,833 (3,970) Accounts payable................................... (54,140) 26,894 (65,990) 18,845 Accrued taxes...................................... 15,801 3,313 16,283 12,694 Accrued interest................................... (3,514) (3,988) (2,365) (4,046) Prepayment and other current assets................ 3,263 1,740 (5,716) 12,671 Other.............................................. (6,039) 4,651 (11,576) (11,412) -------- -------- -------- -------- Net cash provided from operating activities...... 24,462 98,029 9,440 139,321 -------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net........................... 122,451 13,279 254,041 130,234 Equity contributions from parent..................... -- 100,000 -- 100,000 Redemptions and Repayments- Preferred stock...................................... -- -- -- (85,299) Long-term debt....................................... (34,981) (167,705) (117,743) (179,968) Dividend Payments- Common stock......................................... -- -- -- (5,600) Preferred stock...................................... (2,205) (2,211) (6,626) (7,846) -------- -------- -------- -------- Net cash provided from (used for) financing activities ..................................... 85,265 (56,637) 129,672 (48,479) -------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... (20,043) (26,636) (54,825) (66,897) Notes receivable from associated companies, net........ 138 (10,798) (8,602) (19,005) Capital trust investments.............................. 3,399 3,207 20,989 20,033 Contributions to nuclear decommissioning trust ........ (14,271) (7,135) (21,406) (21,406) Debt remarketing investments .......................... (73,231) -- (73,231) -- Other.................................................. (4,752) 36 (11,450) (3,350) -------- -------- -------- -------- Net cash used for investing activities........... (108,760) (41,326) (148,525) (90,625) -------- -------- -------- -------- Net increase (decrease) in cash and cash equivalents...... 967 66 (9,413) 217 Cash and cash equivalents at beginning of period.......... 10,308 453 20,688 302 -------- -------- -------- -------- Cash and cash equivalents at end of period................ $ 11,275 $ 519 $ 11,275 $ 519 ======== ======== ======== ======== <FN> The preceding Notes to Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements. </FN> </TABLE> 85
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 September 30, 2003, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for each of the three-month and nine-month periods ended September 30, 2002. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common 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 goodwill in 2002 as discussed in Note 1(D) to those consolidated financial statements and the Company's restatement of its previously issued consolidated financial statements as of December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002 as discussed in Note 1(M) to those consolidated financial statements) dated August 18, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2003 86
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 portions of Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain them as their power supplier. TE provides power directly to wholesale customers under previously negotiated contracts, as well as to alternative energy suppliers under TE's transition plan. TE has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of TE are provided by FES - an affiliated company. RESTATEMENTS As further discussed in Note 1 to the Consolidated Financial Statements, TE restated its consolidated financial statements for the three years ended December 31, 2002 and the three months ended March 31, 2003 to reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. These restatements were completed and reported in the second quarter of 2003. Financial comparisons described below for the three-month and nine month-periods reflect the effect of these restatements. RESULTS OF OPERATIONS Earnings on common stock in the third quarter of 2003 increased to $13.5 million from earnings of $5.5 million in the third quarter of 2002. Earnings on common stock in the first nine months of 2003 included an after-tax credit of $25.6 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $4.6 million in the first nine months of 2003, compared to $24.6 million for the same period of 2002. The increase in the third quarter 2003 reflected lower fuel and purchased power costs, depreciation and amortization and financing costs partially offset by lower operating revenues and higher nuclear operating costs. In the first nine months of 2003, results were adversely affected by lower operating revenues and higher nuclear operating costs partially offset by lower fuel and purchased power costs and reduced financing costs. Operating revenues decreased by $9.7 million or 3.6% in the third quarter and $64.7 million or 8.4% in the first nine months of 2003 from the same periods in 2002. Reduced revenues resulted from lower kilowatt-hour sales due to milder weather in the second and third quarters, continued sluggishness in the regional economy and increased sales by alternative suppliers. The decline in revenues primarily resulted from lower generation sales revenues from all retail customer sectors. Kilowatt-hour sales to retail customers declined by 9.9% in the third quarter and 10.1% in the first nine months of 2003 from the same periods of 2002, which reduced generation retail sales revenues by $16.4 million and $43.5 million, respectively. Electric generation services provided to retail customers by alternative suppliers as a percent of total sales delivered in TE's service area increased 6.0 percentage points in the third quarter and 7.0 percentage points during the first nine months of 2003 from the corresponding periods last year. Distribution deliveries decreased 2.7% in the third quarter and 1.9% in the first nine months of 2003 compared to the corresponding periods of 2002. However, higher unit prices resulted in overall revenue increases from electricity throughput of $2.7 million and $12.5 million in the third quarter and first nine months of 2003, respectively, compared to 2002. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, reduced revenues by $2.2 million in the third quarter and $5.6 million in the first nine months of 2003 compared to the same periods last year. These revenue reductions are deferred for future recovery under TE's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers increased by $4.9 million in the third quarter and decreased by $22.3 million in the first nine months of 2003 compared with the same periods of 2002. Both periods reflected lower kilowatt-hour sales to the wholesale market due to reduced nuclear generation available for sale to FES. The third quarter increase in revenues reflected the effect of higher unit prices partially offset by lower sales volume. Changes in electric generation sales and distribution deliveries in the third quarter and the first nine months of 2003 from the third quarter and first nine months of 2002 are summarized in the following table: 87
Changes in Kilowatt-Hour Sales Three Months Nine Months --------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail (9.9)% (10.1)% Wholesale............................. (4.1)% (17.2)% ------------------------------------------------------------------- Total Electric Generation Sales......... (7.5)% (13.2)% =================================================================== Distribution Deliveries: Residential (13.0)% (4.3)% Commercial 9.3% 2.5% Industrial............................ (3.9)% (3.4)% ------------------------------------------------------------------- Total Distribution Deliveries........... (2.7)% (1.9)% =================================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $9.7 million in the third quarter and $29.8 million in the first nine months of 2003 from the same periods in 2002. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes Three Months Nine Months --------------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel......................................... $(6.6) $ (12.0) Purchased power costs........................ (3.5) (16.8) Nuclear operating costs...................... 3.5 16.9 Other operating costs........................ 0.8 8.8 ------------------------------------------------------------------------ Total operation and maintenance expenses... (5.8) (3.1) Provision for depreciation and amortization.. (5.7) (10.5) General taxes................................ 0.3 2.0 Income taxes................................. 1.5 (18.2) ------------------------------------------------------------------------- Net decrease in operating expenses and taxes $(9.7) $ (29.8) ========================================================================== Lower fuel costs in the third quarter and first nine months of 2003, compared with the same quarter and nine months of 2002, resulted from reduced nuclear generation (down 9.7% and 24.6%, respectively). The lower purchased power costs reflect reduced kilowatt-hours required for customer needs which more than offset an increase in unit costs. Increased nuclear costs resulted from incremental costs associated with the extended Davis-Besse outage, unplanned work performed during the Perry Plant's 56-day nuclear refueling outage (19.91% ownership) in the second quarter of 2003, and the 28-day refueling outage at Beaver Valley Unit 2 (19.91% interest) in the third quarter of 2003 compared with a 24-day refueling outage at Beaver Valley Unit 2, in the first quarter of 2002. The increase in other operating costs resulted in part from higher employee benefit costs and energy delivery costs as a result of storm damage. Charges for depreciation and amortization decreased by $5.7 million in the third quarter of 2003, compared with the third quarter of 2002 primarily from four factors - higher shopping incentive deferrals ($2.2 million), lower charges resulting from the implementation of SFAS 143 ($3.9 million), revised service life assumptions for generating plants ($3.0 million) and a slight decline in amortization of regulatory assets being recovered under TE's transition plan ($0.4 million). Partially offsetting these decreases were the recognition of depreciation on the Bay Shore generating plant ($1.4 million) which had been held pending sale in the second quarter of 2002 but was subsequently retained by FirstEnergy in the fourth quarter of 2002 and reduced regulatory asset deferrals ($0.9 million). In the first nine months of 2003, depreciation and amortization decreased by $10.5 million compared to the corresponding period of 2002 as a result of the same factors which impacted the third quarter comparison - higher shopping incentive deferrals ($5.6 million), lower charges resulting from implementation of SFAS 143 ($12.1 million) and revised service life assumptions ($8.0 million). Partially offsetting these decreases were increased amortization of regulatory assets being recovered under TE's transition plan ($5.0 million), recognition of depreciation on the Bay Shore generating plant ($4.1 million) and reduced regulatory asset deferrals ($2.5 million). Net Interest Charges Net interest charges continued to trend lower, decreasing by $6.2 million in the third quarter and $14.4 million in the first nine months of 2003 from the same periods last year, reflecting security redemptions and refinancings since the beginning of the third quarter of 2002. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded an after-tax credit to net income of $25.6 million. TE identified applicable legal 88
obligations as defined under the new accounting standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $41.1 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $5.5 million. The asset retirement obligation liability at the date of adoption was $172 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, TE had recorded decommissioning liabilities of $179.6 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $43.8 million increase to income, or $25.6 million net of income taxes. CAPITAL RESOURCES AND LIQUIDITY TE's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without significantly 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 September 30, 2003, TE had $11.3 million of cash and cash equivalents, compared with $20.7 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided by operating activities during the third quarter and first nine months of 2003, compared with the corresponding periods in 2002 were as follows: Three Months Ended Nine Months Ended September 30, September 30, ------------------ ------------------ Operating Cash Flows 2003 2002 2003 2002 ------------------------------------------------------------------------ (In millions) Cash earnings (1)........ $ 45 $45 $ 66 $ 99 Working capital and other (21) 53 (57) 40 ------------------------------------------------------------------------ Total.................... $ 24 $98 $ 9 $139 ======================================================================== (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities decreased by $74 million in the third quarter and $130 million in the first nine months of 2003 compared to the same periods of 2002. The third quarter decrease in funds from operating activities resulted from the decrease in cash provided from working capital. The change in working capital and other primarily reflected an $81 million decrease from accounts payable changes in the third quarter of 2003 compared to the third quarter of 2002. The decrease in the first nine months of 2003 consisted of a $97 million decrease in working capital and other, and a $33 million decrease in cash earnings. The largest factor contributing to the working capital and other decrease was an $85 million change in accounts payable while the cash earnings decrease was attributable to lower electric sales revenues and higher nuclear operating costs. Cash Flows From Financing Activities In the third quarter of 2003, net cash provided from financing activities increased to $85 million from $57 million of net cash used in the third quarter of 2002. This increase in cash provided from financing activities primarily resulted from lower security redemptions and repayments. In the first nine months of 2003, net cash provided from financing activities increased to $130 million from $48 million of net cash used in financing activities in the same period of 2002. This change was due to a $147 million decrease in redemptions in 2003 compared to 2002. TE had approximately $20.4 million of cash and temporary investments and approximately $403.7 million of short-term indebtedness as of September 30, 2003. TE is currently precluded from issuing first mortgage bonds or preferred stock based upon applicable earnings coverage tests as of September 30, 2003. Cash Flows From Investing Activities Net cash used for investing activities increased $67 million between the third quarter of 2003 and the same quarter of 2002 due to changes in nuclear decommissioning trust investments. 89
During the fourth quarter of 2003, capital requirements for property additions and capital leases are expected to be about $18 million. TE has no requirements to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. On November 13, 2003, FirstEnergy announced that it had reached an agreement with NRG covering the settlement of its claims resulting from the uncompleted sale of four power plants to NRG, one of which was a TE generating plant (Bay Shore). Under the agreement FirstEnergy would receive an estimated settlement for the four plants of approximately $198 million in the form of cash (12%), notes (15.2%) and common stock (72.8%). The agreement is subject to FERC authorization and U.S. Bankruptcy Court approval since NRG and certain of its subsidiaries filed for voluntary bankruptcy in May 2003. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI, and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the securities of its electric utility operating companies. Fitch stated that the changes to the long-term ratings were "driven by the high debt leverage of the parent FE. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been vulnerable to unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable Outlook reflects the success of FE's recent common equity offering and management's focus on a relatively conservative integrated utility strategy." On October 27, 2003, Standard & Poors (S&P) stated that the `BBB' corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its utility subsidiaries remain on CreditWatch with negative implications. The ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's concerns regarding the potential impact of the August 14, 2003 blackout investigation on FirstEnergy's deleveraging strategy and its overall efforts to improve its credit profile. At that time, S&P also noted other challenges facing FirstEnergy, including the extended Davis-Besse outage; the recent U.S. District Court ruling regarding the Sammis Plant; reliability concerns in subsidiary JCP&L's service territory; and FirstEnergy's credibility with regulators and federal officials. S&P further noted several factors that could aid FirstEnergy in resolution of the CreditWatch, including strengthening its balance sheet. FirstEnergy directly addressed this concern through its recently completed common equity offering that raised approximately $935 million in net proceeds, which was used to reduce bank debt. S&P described the equity offering as a "positive credit development" and also noted the recent renewal of FirstEnergy's $1 billion revolver facilities as a "favorable development, as it mitigates liquidity concerns." S&P also indicated that should various ongoing investigations into the causal factors of the August 14, 2003 blackout establish that the blackout resulted from no negligence or breach of compliance standards on FirstEnergy's part, the CreditWatch could be removed and the outlook returned to negative. S&P deemed a "stable" credit outlook unlikely until issues such as the restart of Davis-Besse are resolved and the potential effect of the litigation relating to the Sammis plant (the second trial is scheduled for April 2004) are known. Extension of the Ohio transition plan will be viewed as a positive development and will support an outlook revision to stable. On October 27, 2003, S&P also noted that the ratings on FirstEnergy and its subsidiaries incorporate such strengths as the ability to generate free cash flow, power generation contracted to its transmission and distribution subsidiaries through 2005, and the hedging of its short power position arising from its PLR obligation in Pennsylvania. S&P said that these strengths are offset by slower than anticipated reduction of FirstEnergy debt, remaining volume risks of PLR obligations, the extended outage at Davis-Besse, the unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty in Ohio. S&P also said that it now views FirstEnergy's liquidity position as average, following FirstEnergy's renewal of its $1 billion credit facilities. Other Obligations Obligations not included on TE's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of September 30, 2003, the present value of these 90
sale and leaseback operating lease commitments, net of trust investments, totaled $595 million. TE also sells substantially all of its retail customer receivables, which provided $67 million of off-balance sheet financing as of September 30, 2003. EQUITY PRICE RISK Included in TE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $122 million and $90 million as of September 30, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12 million reduction in fair value as of September 30, 2003. OUTLOOK Beginning in 2001, TE's customers were able to select alternative energy suppliers. TE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. TE has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of TE's Ohio customers elects to obtain power from an alternative supplier, TE reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. TE has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by The Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets declined by $62.0 million for the first nine months of 2003, to $516.3 million as of September 30, 2003 resulting from recovery of transition plan regulatory assets. As part of TE's transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. TE is also required to provide 160 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within its service area. TE's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. On October 21, 2003, the Ohio Companies 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 supply and continuing FirstEnergy's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service, including PLR responsibility, for FirstEnergy's Ohio 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 FirstEnergy's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity as discussed above. In order to facilitate supply planning, FirstEnergy has requested that the PUCO rule on this proposal by December 31, 2003. Under the proposed plan, TE is requesting: o Extension of the transition cost amortization period for TE from mid-2007 to 2008; o Deferral of new regulatory assets and deferral of interest costs on the shopping incentive and other new deferrals; 91
o Ability to initiate a request to increase generation rates only under certain limited conditions. As a result of the Ohio Companies' October 21 filing, the PUCO entered an order on October 28, 2003 setting forth the discovery schedule related to the application with hearings scheduled to begin December 3, 2003. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FirstEnergy is also accelerating maintenance work that had been planned for future refueling and maintenance outages. Testing of the bottom of the reactor for leaks was completed in October 2003 and no indication of leakage was discovered. FirstEnergy is installing a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FirstEnergy anticipates that the unit will be ready for restart in the fall of 2003. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed FirstEnergy's plans to reduce post-merger debt levels FirstEnergy believes such investments in the unit's future safety, reliability and performance to be essential. Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). Incremental costs associated with the extended Davis-Besse outage (TE's share - 48.62%) for the third quarter and first nine months of 2003 and 2002 were as follows: Three Months Ended Nine Months Ended Costs of Davis-Besse Extended Outage September 30 September 30 ---------------------------------------------------------------------------- 2003 2002 2003 2002 ---- ---- ---- ---- (In millions) Incremental Pre-Tax Expense Replacement power $54.9 $50.9 $148.4 $ 84.5 Maintenance 17.5 39.8 75.7 54.1 ---------------------------------------------------------------------------- Total $72.4 $90.7 $224.1 $138.6 ============================================================================ Capital Expenditures $10.9 $27.4 $ 13.3 $ 39.4 ============================================================================ It is anticipated that an additional $14 million in maintenance costs will be expended over the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month during the remaining period of the outage. FirstEnergy has hedged the on-peak replacement energy supply for Davis-Besse for the expected length of the outage. If there are significant delays in the NRC approval process, substantial replacement power costs will continue to be incurred, which will continue to have an adverse effect on TE's cash flows and results of operations. Environmental Matters TE believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2C - Environmental Matters). TE continues to evaluate its compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric 92
power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. TE believes it is in compliance with the current SO2 and NOx reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that required compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at TE's Ohio facilities by May 31, 2004. TE has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved, are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2003, based on estimates of the total costs of cleanup, TE's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. TE has total accrued liabilities of approximately $0.2 million as of September 30, 2003. The effects of compliance on TE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect its earnings and competitive position to the extent TE competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. TE believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Legal Matters Various lawsuits, claims and proceedings related to TE's normal business operations are pending against TE, the most significant of which are described above. SIGNIFICANT ACCOUNTING POLICIES TE prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect TE's financial results. All of TE's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. TE's more significant accounting policies are described below. Regulatory Accounting TE is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine TE is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio, a significant amount of regulatory assets have been recorded - $516.3 million as of September 30, 2003. 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. 93
Revenue Recognition TE follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension and OPEB benefits are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy is not required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's restructuring 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. 94
Long-Lived Assets In accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," TE periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, TE recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, TE evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were 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 evaluation of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of September 30, 2003, TE had approximately $505 million of goodwill. RECENTLY ISSUED ACCOUNTING STANDARDS FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". This Interpretation requires the consolidation of a variable interest entity (VIE) by an enterprise if that enterprise either absorbs a majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns as a result of ownership, contractual or other financial interests in the VIE. Currently, entities are generally consolidated by an enterprise that has a controlling financial interest through ownership of a majority voting interest in the entity. FIN 46 defines a VIE as an entity in which equity investors do not have the characteristics of a controlling financial interest nor have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. VIE's created after January 31, 2003, are immediately subject to the provisions of FIN 46. The FASB recently deferred implementation of FIN 46 for VIE's created before February 1, 2003, until the first reporting period ending after December 15, 2003 (TE's quarter ending December 31, 2003.) TE currently has transactions with entities in connection with sale and leaseback arrangements which may fall within the scope of this interpretation and which meet the definition of a VIE in accordance with FIN 46. One such entity is the Shippingport Capital Trust which acquired all of the lease obligation bonds issued in connection with the sale and leaseback in 1987 of interests in the Bruce Mansfield Plant held by TE and CEI, an affiliated company. The equity ownership of this trust includes a 0.34% interest held by Toledo Edison Capital Corporation, a majority owned subsidiary, and 4.85% interests held by unaffiliated third parties. The assets and liabilities of the trust are currently included on a proportionate basis in the financial statements of TE and CEI. Adoption of FIN 46 may result in reporting all of the trust assets and liabilities on the books of CEI. TE is also evaluating its interests in the owner trusts that acquired the interests in the Bruce Mansfield Plant and Beaver Valley Unit 2. TE has not completed its evaluation to determine if it would be the primary beneficiary and therefore required to consolidate these trusts. The FASB continues to provide additional guidance on implementing FIN 46 and recently proposed modifications and clarifications with a comment period ending December 1, 2003. As this guidance is finalized, TE will continue to assess the accounting and disclosure impact of FIN 46 with respect to the VIE's discussed above as well as other potential VIE's. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus on Issue No. 01-08, regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus is to be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. The adoption of this consensus as of July 1, 2003 did not impact TE's financial statements. 95
<TABLE> <CAPTION> PENNSYLVANIA POWER COMPANY STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ------------------------ ------------------------ 2003 2002 2003 2002 ---------- ---------- ---------- ---------- (In thousands) <S> <C> <C> <C> <C> OPERATING REVENUES........................................ $145,904 $131,917 $390,806 $383,989 -------- -------- -------- -------- OPERATING EXPENSES AND TAXES: Fuel................................................... 6,142 6,568 15,073 19,280 Purchased power........................................ 44,761 40,057 125,781 115,683 Nuclear operating costs................................ 25,448 19,155 107,806 60,960 Other operating costs.................................. 15,141 13,365 41,750 33,034 -------- -------- -------- -------- Total operation and maintenance expenses........... 91,492 79,145 290,410 228,957 Provision for depreciation and amortization............ 13,461 14,203 40,206 42,615 General taxes.......................................... 6,093 6,720 18,151 18,730 Income taxes........................................... 14,990 13,044 17,779 38,295 -------- -------- -------- -------- Total operating expenses and taxes................. 126,036 113,112 366,546 328,597 -------- -------- -------- -------- OPERATING INCOME.......................................... 19,868 18,805 24,260 55,392 OTHER INCOME.............................................. 465 739 1,589 1,880 -------- -------- -------- -------- INCOME BEFORE NET INTEREST CHARGES........................ 20,333 19,544 25,849 57,272 -------- -------- -------- -------- NET INTEREST CHARGES: Interest expense....................................... 3,788 4,188 11,964 12,554 Allowance for borrowed funds used during construction.. (844) (447) (2,172) (1,044) -------- -------- -------- -------- Net interest charges............................... 2,944 3,741 9,792 11,510 -------- -------- -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ................................................... 17,389 15,803 16,057 45,762 Cumulative effect of accounting change (net of income taxes of $7,532,000) (Note 5).......................... -- -- 10,618 -- -------- -------- -------- -------- NET INCOME................................................ 17,389 15,803 26,675 45,762 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 639 926 2,462 2,778 -------- -------- -------- -------- EARNINGS ON COMMON STOCK.................................. $ 16,750 $ 14,877 $ 24,213 $ 42,984 ======== ======== ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements. </FN> </TABLE> 96
<TABLE> <CAPTION> PENNSYLVANIA POWER COMPANY BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (In thousands) ASSETS ------ <S> <C> <C> UTILITY PLANT: In service................................................................ $793,153 $680,729 Less--Accumulated provision for depreciation.............................. 323,714 316,424 -------- -------- 469,439 364,305 -------- -------- Construction work in progress- Electric plant.......................................................... 63,054 44,696 Nuclear fuel............................................................ 4,050 8,812 -------- -------- 67,104 53,508 -------- -------- 536,543 417,813 -------- -------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 127,212 119,401 Long-term notes receivable from associated companies...................... 39,493 38,921 Other..................................................................... 2,131 2,569 -------- -------- 168,836 160,891 -------- -------- CURRENT ASSETS: Cash and cash equivalents................................................. 41 1,222 Receivables- Customers (less accumulated provisions of $747,000 and $702,000, respectively, for uncollectible accounts)............................. 45,511 44,341 Associated companies.................................................... 27,540 42,652 Other................................................................... 1,681 5,262 Notes receivable from associated companies................................ 486 35,317 Materials and supplies, at average cost................................... 30,874 30,309 Prepayments............................................................... 12,321 5,346 -------- -------- 118,454 164,449 -------- -------- DEFERRED CHARGES: Regulatory assets......................................................... 50,157 156,903 Other..................................................................... 7,447 7,692 -------- -------- 57,604 164,595 -------- -------- $881,437 $907,748 ======== ======== </TABLE> 97
<TABLE> <CAPTION> PENNSYLVANIA POWER COMPANY BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ <S> <C> <C> 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.................................... (22,259) (9,932) Retained earnings....................................................... 38,129 50,916 -------- -------- Total common stockholder's equity................................... 204,260 229,374 Preferred stock- Not subject to mandatory redemption..................................... 39,105 39,105 Subject to mandatory redemption (Note 5)................................ -- 13,500 Long-term debt and other long-term obligations- Preferred stock subject to mandatory redemption (Note 5)................ 13,500 -- Other................................................................... 150,538 185,499 -------- -------- 407,403 467,478 -------- -------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock (Note 5)............. 61,024 66,556 Accounts payable- Associated companies.................................................... 51,352 52,653 Other................................................................... 360 5,730 Notes payable to associated companies..................................... 8,290 -- Accrued taxes............................................................. 35,332 12,507 Accrued interest.......................................................... 3,086 5,558 Other..................................................................... 9,091 10,479 -------- -------- 168,535 153,483 -------- -------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 97,513 117,385 Accumulated deferred investment tax credits............................... 3,590 3,810 Asset retirement obligation............................................... 127,450 -- Nuclear plant decommissioning costs....................................... -- 119,863 Other..................................................................... 76,946 45,729 -------- -------- 305,499 286,787 -------- -------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... -------- -------- $881,437 $907,748 ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets. </FN> </TABLE> 98
<TABLE> <CAPTION> PENNSYLVANIA POWER COMPANY STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2003 2002 2003 2002 -------- -------- -------- -------- (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 17,389 $ 15,803 $ 26,675 $ 45,762 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 13,461 14,203 40,206 42,615 Nuclear fuel and lease amortization................ 4,607 5,054 11,396 14,622 Deferred income taxes, net......................... (2,378) (1,731) 1,376 (5,606) Amortization of investment tax credits............. (598) (643) (1,826) (1,963) Cumulative effect of accounting change (Note 5).... -- -- (18,150) -- Receivables........................................ (9,122) 376 12,418 (3,644) Materials and supplies............................. (45) (1,766) (565) (4,049) Accounts payable................................... 1,244 161 (917) (18,745) Accrued taxes...................................... 14,024 (18,063) 22,825 5,026 Accrued interest................................... (2,496) (1,849) (2,472) (1,780) Prepayments and other current assets............... 5,503 4,886 (6,975) (3,897) Other.............................................. 4,026 1,461 11,222 2,013 -------- -------- -------- -------- Net cash provided from operating activities...... 45,615 17,892 95,213 70,354 -------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... -- 14,500 -- 14,500 Short-term borrowings, net........................... 8,290 -- 8,290 -- Redemptions and Repayments- Long-term debt....................................... (40,052) (15,031) (40,669) (56,321) Dividend Payments- Common stock......................................... (11,000) (20,700) (37,000) (28,500) Preferred stock...................................... (911) (926) (2,734) (2,778) -------- -------- -------- -------- Net cash used for financing activities........... (43,673) (22,157) (72,113) (73,099) -------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... (12,017) (8,210) (52,751) (24,636) Contributions to nuclear decommissioning trusts........ (797) (399) (1,196) (1,196) Notes receivable from associated companies, net........ 9,646 14,982 34,259 31,856 Other.................................................. 1,226 (1,244) (4,593) (1,892) -------- -------- -------- -------- Net cash provided from (used for) investing activities ..................................... (1,942) 5,129 (24,281) 4,132 -------- -------- -------- -------- Net increase (decrease) in cash and cash equivalents...... -- 864 (1,181) 1,387 Cash and cash equivalents at beginning of period.......... 41 590 1,222 67 -------- -------- -------- -------- Cash and cash equivalents at end of period................ $ 41 $ 1,454 $ 41 $ 1,454 ======== ======== ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements. </FN> </TABLE> 99
REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Pennsylvania Power Company: We have reviewed the accompanying balance sheet of Pennsylvania Power Company as of September 30, 2003, and the related statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited in accordance with auditing standards generally accepted in the United States of America, the balance sheet and the statement of capitalization as of December 31, 2002, and the related statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2003 100
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. RESULTS OF OPERATIONS Earnings on common stock in the third quarter of 2003 increased to $16.8 million from $14.9 million in the third quarter of 2002. In the first nine months of 2003, earnings on common stock decreased to $24.2 million from $43.0 million in the first nine months of 2002. Earnings in the first nine months of 2003 included an after-tax credit of $10.6 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $16.1 million in the first nine months of 2003 compared to income of $45.8 million for the same period of 2002. The increased earnings in the third quarter of 2003 reflected higher operating revenues, but were partially offset by higher operating costs - primarily nuclear operating costs, purchased power and employee benefit costs. The lower results for the first nine months of 2003 were primarily due to higher nuclear operating costs, purchased power costs and employee benefit costs. These increased costs were partially offset by higher operating revenues, lower fuel costs and reduced financing costs. Operating revenues increased by $14.0 million, or 10.6%, in the third quarter and $6.8 million, or 1.8%, in the first nine months of 2003 compared with the same periods of 2002. The higher revenues primarily resulted from increased wholesale revenues of $10.1 million and $10.5 million in the third quarter and first nine months of 2003, respectively, as compared to the same periods of 2002. In addition, higher retail generation sales revenues contributed $3.5 million and $0.9 million in the third quarter and first nine months, respectively. Distribution deliveries increased 2.9% in the third quarter of 2003 compared with the same quarter in 2002. This increase reflected increases in commercial and industrial sales of 6.9% and 6.0%, respectively, partially offset by a residential customer sales decrease of 3.1% caused by the milder weather in the third quarter of 2003 which reduced air conditioning demands. This weather-related effect resulted in a nearly flat change in distribution delivery revenues in the third quarter of 2003 from the same quarter of 2002. In the first nine months of 2003, distribution deliveries decreased 1.2% compared with the corresponding period of 2002, principally reflecting decreases in the residential and industrial customer sectors. The residential customer sales decreases were caused by the milder weather in the second and third quarters of 2003 which also reduced air conditioning demands and was the primary cause of lower electricity throughput revenues of $4.6 million in the first nine months of 2003 from the same period of the prior year. Wholesale revenues from sales to FES increased by $11.0 million in the third quarter and $9.2 million in the first nine months of 2003. These increases reflected higher unit prices, which were partially offset by lower kilowatt-hour sales due to reduced nuclear generation available for sale to FES. Changes in electric generation sales and distribution deliveries in the third quarter and first nine months of 2003 from the same periods of 2002 are summarized in the following table: Changes in Kilowatt-Hour Sales Three Months Nine Months ------------------------------------------------------------------ Increase (Decrease) Electric Generation: Retail............................. 3.0% (0.9)% Wholesale.......................... (2.3)% (17.3)% ----------------------------------------------------------------- Total Electric Generation Sales....... (0.2)% (10.8)% ================================================================= Distribution Deliveries: Residential........................ (3.1)% (1.9)% Commercial......................... 6.9% 2.0% Industrial......................... 6.0% (3.1)% ----------------------------------------------------------------- Total Distribution Deliveries......... 2.9% (1.2)% ================================================================= 101
Operating Expenses and Taxes Total operating expenses and taxes increased by $12.9 million in the third quarter and $38.0 million in the first nine months of 2003 from the third quarter and first nine months of 2002. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes Three Months Nine Months ------------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel......................................... $(0.4) $ (4.2) Purchased power costs........................ 4.7 10.1 Nuclear operating costs...................... 6.3 46.9 Other operating costs........................ 1.7 8.7 ------------------------------------------------------------------------- Total operation and maintenance expenses.. 12.3 61.5 Provision for depreciation and amortization.. (0.7) (2.4) General taxes................................ (0.6) (0.6) Income taxes................................. 1.9 (20.5) ------------------------------------------------------------------------- Total increase in operating expenses and taxes $12.9 $ 38.0 ========================================================================= Lower fuel costs in the third quarter and first nine months of 2003, compared with the same periods of 2002, resulted from reduced nuclear generation. The increased purchased power costs in both periods of 2003 reflected higher units costs and increased kilowatt-hour purchases. Higher nuclear operating costs occurred, in large part, due to the refueling outages at Beaver Valley Unit 1 (65.00% ownership) in the first quarter of 2003; at Perry (5.24% ownership) in the second quarter of 2003; and at Beaver Valley Unit 2 (13.74% ownership) in the third quarter of 2003, compared with one refueling outage at Beaver Valley Unit 2 in the first quarter of 2002. The increase in other operating costs reflects higher employee benefit costs and increased uncollectible customer accounts. Charges for depreciation and amortization decreased by $0.7 million in the third quarter and $2.4 million in the first nine months of 2003 compared to the third quarter and first nine months of 2002 primarily from lower charges resulting from the implementation of SFAS 143 ($0.3 million for the third quarter and $1.2 million for the first nine months of 2003) and revised service life assumptions for generating plants ($0.3 million for the third quarter and $0.9 million for the first nine months of 2003). Net Interest Charges Net interest charges continued to trend lower, decreasing by approximately $0.8 million in the third quarter and $1.7 million in the first nine months of 2003 from the same periods last year, reflecting redemptions and refinancings since the beginning of the third quarter of 2002. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Penn recorded an after-tax credit to net income of $10.6 million. Penn identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $78 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $9 million. The asset retirement obligation (ARO) liability at the date of adoption was $121 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, Penn had recorded decommissioning liabilities of $120 million. Penn expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, it recognized a regulatory liability of $69 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning. The remaining cumulative effect adjustment for unrecognized depreciation, offset by the reduction in the liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component, was an $18.2 million increase to income, or $10.6 million net of income taxes (see Note 5). CAPITAL RESOURCES AND LIQUIDITY Penn's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without materially increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, Penn expects to meet its contractual obligations with cash from operations. Thereafter, Penn expects to use a combination of cash from operations and funds from the capital markets. 102
Changes in Cash Position As of September 30, 2003, Penn had $41,000 of cash and cash equivalents, compared with $1.2 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from operating activities during the third quarter and first nine months of 2003, compared with the corresponding periods in 2002 were as follows: Three Months Ended Nine Months Ended September 30, September 30, ------------------------------------------ Operating Cash Flows 2003 2002 2003 2002 ------------------------------------------------------------------------ (In millions) Cash earnings (1)........ $36 $ 34 $63 $ 96 Working capital and other 10 (16) 32 (26) ------------------------------------------------------------------------ Total ............ $46 $ 18 $95 $ 70 ======================================================================== (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash from operating activities increased to $46 million in the third quarter and $95 million in the first nine months of 2003 compared with $18 million and $70 million, respectively, in the same periods of 2002. The increase in working capital and other primarily was due to an increase of $32 million in accrued tax liabilities partially offset by a decrease in accounts receivable of $9 million in the third quarter of 2003 compared with corresponding changes in the third quarter of 2002. Cash Flows From Financing Activities In the third quarter of 2003, net cash used for financing activities increased to $44 million from $22 million in the same period last year. The increase resulted from an increase in redemptions in 2003 compared to 2002. Penn had approximately $0.5 million of cash and temporary investments, primarily composed of notes receivable from associated companies and approximately $8.3 million of short-term indebtedness as of September 30, 2003. Penn may borrow from its affiliates on a short-term basis. Penn had the capability to issue $230 million of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests, Penn could not issue preferred stock as of September 30, 2003. Cash Flows From Investing Activities Net cash used for investing activities totaled $2 million in the third quarter and $24 million in the first nine months of 2003, compared to net cash provided from investing activities of $5 million and $4 million for the same periods of 2002, respectively. The $7 million change in funds for the third quarter resulted from lower payments received on notes from associated companies and higher property additions as compared to 2002. During the fourth quarter of 2003, capital requirements for property additions and capital leases are expected to be about $13 million. Penn has additional requirements of approximately $1.2 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the fourth quarter of 2003. These requirements are expected to be satisfied from internal cash and short-term credit arrangements. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse (Penn has no ownership interest in this facility). Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI, and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the securities of its electric utility operating companies. Fitch stated that the changes to the long-term debt ratings were "driven by the high debt leverage of the parent FirstEnergy. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been 103
vulnerable to unfavorable events, slowing the pace of FirstEnergy's debt reduction efforts. The Stable Outlook reflects the success of FirstEnergy's recent common equity offering and management's focus on a relatively conservative integrated utility strategy." On October 27, 2003, Standard & Poors (S&P) stated that the `BBB' corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its utility subsidiaries remain on CreditWatch with negative implications. The ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's concerns regarding the potential impact of the August 14, 2003 blackout investigation on FirstEnergy's deleveraging strategy and its overall efforts to improve its credit profile. At that time, S&P also noted other challenges facing FirstEnergy, including the extended Davis-Besse outage; the recent U.S. District Court ruling regarding the Sammis Plant (see Environmental Matters below); reliability concerns in subsidiary JCP&L's service territory; and FirstEnergy's credibility with regulators and federal officials. S&P further noted several factors that could aid FirstEnergy in resolution of the CreditWatch, including strengthening its balance sheet. FirstEnergy directly addressed this concern through its recently completed common equity offering that raised approximately $935 million in net proceeds, which was used to reduce bank debt. S&P described the equity offering as a "positive credit development" and also noted the recent renewal of FirstEnergy's $1 billion revolver facilities as a "favorable development, as it mitigates liquidity concerns." S&P also indicated that should various ongoing investigations into the causal factors of the August 14, 2003 blackout establish that the blackout resulted from no negligence or breach of compliance standards on FirstEnergy's part, the CreditWatch could be removed and the outlook returned to negative. S&P deemed a "stable" credit outlook unlikely until issues such as the restart of Davis-Besse are resolved and the potential effect of the litigation relating to the Sammis plant (the second trial is scheduled for April 2004) are known. Extension of the Ohio transition plan will be viewed as a positive development and will support an outlook revision to stable. On October 27, 2003, S&P also noted that the ratings on FirstEnergy and its subsidiaries incorporate such strengths as the ability to generate free cash flow, power generation contracted to its transmission and distribution subsidiaries through 2005, and the hedging of its short power position arising from its PLR obligation in Pennsylvania. S&P said that these strengths are offset by slower than anticipated reduction of FirstEnergy debt, remaining volume risks of PLR obligations, the extended outage at Davis-Besse, the unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty in Ohio. S&P also said that it now views FirstEnergy's liquidity position as average, following FirstEnergy's renewal of its $1 billion credit facilities. EQUITY PRICE RISK Included in Penn's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $45 million and $38 million as of September 30, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $4 million reduction in fair value as of September 30, 2003. OUTLOOK Beginning in 1999, Penn's customers were able to select alternative energy suppliers and customer rates have been restructured into separate components to support customer choice. A number of customers previously served by alternative energy providers have returned to Penn for their energy needs. Penn has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Penn continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Regulatory Matters Regulatory assets are costs which have been authorized by the PPUC and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets declined by $106.7 million during the first nine months of 2003, to $50.2 million as of September 30, 2003; $69.2 million of the decrease related to the cumulative adjustment related to the adoption of SFAS 143. All of Penn's regulatory assets are expected to continue to be recovered under the provisions of its regulatory plan. As part of Penn's transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. Penn's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in Penn's franchise area. 104
Environmental Matters Penn believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from Penn's Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2 - Environmental Matters). Penn continues to evaluate its compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. 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 (CAA). The civil complaint against OE and Penn requests installation of "best available control technology" as well as civil penalties of up to $27,500 per day of violation. On August 7, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning April 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 Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been recorded as of September 30, 2003. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. Penn believes it is in compliance with the current SO2 and NOx reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from its Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that required compliance with the NOx budgets at Penn's Pennsylvania facilities by May 1, 2003. The effects of compliance on Penn with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect Penn's earnings and competitive position to the extent it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Penn believes it is in material compliance with existing regulations, but are unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Legal Matters Various lawsuits, claims and proceedings relayed to Penn's normal business operations are pending against Penn, the most significant of which are described above. 105
SIGNIFICANT ACCOUNTING POLICIES Penn prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect Penn's financial results. All of Penn's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. 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 the costs that the regulatory agencies determine Penn is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded - $50 million as of September 30, 2003. Penn regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition Penn follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. 106
Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy is not required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," Penn periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, Penn recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). RECENTLY ISSUED ACCOUNTING STANDARDS FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". This Interpretation requires the consolidation of a variable interest entity (VIE) by an enterprise if that enterprise either absorbs a majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns as a result of ownership, contractual or other financial interests in the VIE. Currently, entities are generally consolidated by an enterprise that has a controlling financial interest through ownership of a majority voting interest in the entity. FIN 46 defines a VIE as an entity in which equity investors do not have the characteristics of a controlling financial interest nor have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. VIE's created after January 31, 2003, are immediately subject to the provisions of FIN 46. The FASB recently deferred implementation of FIN 46 for VIE's created before February 1, 2003, until the first reporting period ending after December 15, 2003 (Penn's quarter ending December 31, 2003.) The adoption of FIN 46 for variable interests created after January 31, 2003 did not have an impact on Penn's financial statements. We are continuing to review the provisions of FIN 46 to determine its impact, if any, on future reporting periods with respect to interests in VIE's created prior to February 1, 2003, and do not currently anticipate that adoption will result in any material accounting or disclosure requirements. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities Upon adoption of SFAS 150, on July 1, 2003, Penn reclassified as debt its preferred stock subject to mandatory redemption having carrying values of approximately $13.5 million as of September 30, 2003. Prior to the adoption of SFAS 150, dividends on preferred stock subject to mandatory redemption in Penn's Statements of Income were not included in net interest charges. Therefore, the application of SFAS 150 required the reclassification of such preferred dividends to net interest charges. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus on Issue No. 01-08, regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus is to be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. The adoption of this consensus as of July 1, 2003 did not impact Penn's financial statements. 107
<TABLE> <CAPTION> JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- --------------------------- 2003 2002 2003 2002 -------- -------- ---------- ---------- (In thousands) <S> <C> <C> <C> <C> OPERATING REVENUES........................................ $743,145 $779,955 $1,942,868 $1,731,900 -------- -------- ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel................................................... 524 1,873 3,290 4,347 Purchased power........................................ 416,308 453,081 1,260,352 913,532 Other operating costs.................................. 111,204 50,587 263,229 193,204 -------- -------- ---------- ---------- Total operation and maintenance expenses........... 528,036 505,541 1,526,871 1,111,083 Provision for depreciation and amortization............ 68,523 67,645 181,673 186,919 General taxes.......................................... 18,506 17,740 47,282 39,037 Income taxes........................................... 44,461 67,689 51,713 134,093 -------- -------- ---------- ---------- Total operating expenses and taxes................. 659,526 658,615 1,807,539 1,471,132 -------- -------- ---------- ---------- OPERATING INCOME.......................................... 83,619 121,340 135,329 260,768 OTHER INCOME.............................................. 1,061 1,269 4,501 6,291 -------- -------- ---------- ---------- INCOME BEFORE NET INTEREST CHARGES........................ 84,680 122,609 139,830 267,059 -------- -------- ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt............................. 20,888 23,721 66,867 69,206 Allowance for borrowed funds used during construction.. 39 (301) (195) (880) Deferred interest...................................... (1,541) (3,722) (7,667) (5,107) Other interest expense................................. 1,131 (538) 1,076 (2,315) Subsidiary's preferred stock dividend requirements..... -- 2,674 5,348 8,021 -------- -------- ---------- ---------- Net interest charges............................... 20,517 21,834 65,429 68,925 -------- -------- ---------- ---------- NET INCOME................................................ 64,163 100,775 74,401 198,134 PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 125 (2,773) (238) (1,589) -------- -------- ---------- ---------- EARNINGS ON COMMON STOCK.................................. $ 64,038 $103,548 $ 74,639 $ 199,723 ======== ======== ========== ========== <FN> The preceding Notes to Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements. </FN> </TABLE> 108
<TABLE> <CAPTION> JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (In thousands) ASSETS ------ UTILITY PLANT: <S> <C> <C> In service................................................................ $3,603,705 $3,478,803 Less--Accumulated provision for depreciation.............................. 1,500,171 1,343,846 ---------- ---------- 2,103,534 2,134,957 Construction work in progress - electric plant............................ 41,320 20,687 ---------- ---------- 2,144,854 2,155,644 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 117,768 106,820 Nuclear fuel disposal trust............................................... 152,341 149,738 Long-term notes receivable from associated companies...................... 21,317 20,333 Other..................................................................... 24,206 18,202 ---------- ---------- 315,632 295,093 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 1,270 4,823 Receivables- Customers (less accumulated provisions of $4,998,000 and $4,216,000 respectively, for uncollectible accounts).............................. 287,062 247,624 Associated companies.................................................... 88,807 318 Other .................................................................. 41,716 20,134 Notes receivable from associated companies................................ -- 77,358 Materials and supplies, at average cost................................... 2,076 1,341 Prepayments and other..................................................... 58,278 37,719 ---------- ---------- 479,209 389,317 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 2,926,669 3,199,012 Goodwill.................................................................. 2,000,875 2,000,875 Other..................................................................... 12,558 12,814 ---------- ---------- 4,940,102 5,212,701 ---------- ---------- $7,879,797 $8,052,755 ========== ========== </TABLE> 109
<TABLE> <CAPTION> JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ <S> <C> <C> CAPITALIZATION: Common stockholder's equity- Common stock, $10 par value, authorized 16,000,000 shares - 15,371,270 shares outstanding......................................... $ 153,713 $ 153,713 Other paid-in capital................................................... 3,029,218 3,029,218 Accumulated other comprehensive loss.................................... (64,740) (865) Retained earnings....................................................... 38,641 92,003 ---------- ---------- Total common stockholder's equity................................... 3,156,832 3,274,069 Preferred stock not subject to mandatory redemption....................... 12,649 12,649 Company-obligated mandatorily redeemable preferred securities............. -- 125,244 Long-term debt............................................................ 1,261,690 1,210,446 ---------- ---------- 4,431,171 4,622,408 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 15,600 173,815 Accounts payable- Associated companies.................................................... 87,553 170,803 Other................................................................... 121,833 106,504 Notes payable to associated companies..................................... 287,867 -- Accrued taxes............................................................. 29,932 13,844 Accrued interest.......................................................... 26,124 27,161 Other..................................................................... 64,736 112,408 ---------- ---------- 633,645 604,535 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 619,506 691,721 Accumulated deferred investment tax credits............................... 8,232 9,939 Power purchase contract loss liability.................................... 1,599,904 1,710,968 Nuclear fuel disposal costs............................................... 167,537 166,191 Asset retirement obligation............................................... 108,343 -- Retirement benefits...................................................... 192,492 -- Nuclear decommissioning costs............................................. -- 135,355 Other..................................................................... 118,967 111,638 ---------- ---------- 2,814,981 2,825,812 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $7,879,797 $8,052,755 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these balance sheets. </FN> </TABLE> 110
<TABLE> <CAPTION> JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- --------------------------- 2003 2002 2003 2002 -------- -------- ---------- ---------- (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 64,163 $ 100,775 $ 74,401 $ 198,134 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 68,523 67,645 181,673 186,919 Deferred costs, net................................ (34,004) (122,338) (118,337) (231,286) Deferred income taxes, net......................... 7,362 48,583 (9,642) 85,123 Amortization of investment tax credits............. (557) (899) (1,707) (2,698) Accrued retirement benefit obligation.............. 22,739 -- 28,905 -- Accrued compensation, net.......................... (829) -- 20,730 -- Revenue credits to customers....................... (19,583) (17,434) (71,984) (17,434) Disallowed purchased power costs (see Note 4)...... -- -- 152,500 -- Receivables........................................ (30,971) (14,584) (98,573) (4,647) Materials and supplies............................. 37 (1) (735) 44 Accounts payable................................... (105,130) (21,250) (92,791) 11,694 Prepayments and other current assets............... 49,888 41,706 (20,559) (28,944) Accrued taxes...................................... 11,279 7,761 16,088 (20,699) Accrued interest................................... 7,391 8,570 (1,037) 7,060 Other.............................................. (32,954) (2,096) (1,456) 2,356 --------- --------- ---------- ---------- Net cash provided from operating activities ..................................... 7,354 96,438 57,476 185,622 --------- --------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... -- -- 150,000 318,106 Short-term borrowings, net........................... 91,741 -- 287,867 -- Redemptions and Repayments- Preferred stock...................................... -- (46,500) (125,244) (51,500) Long-term debt....................................... (82,388) (146,033) (247,414) (196,033) Short-term borrowings, net........................... -- -- -- (18,149) Dividend Payments- Common stock......................................... -- (57,700) (128,000) (123,700) Preferred stock...................................... -- (256) -- (2,000) --------- --------- ---------- ---------- Net cash provided from (used for) financing activities ..................................... 9,353 (250,489) (62,791) (73,276) --------- --------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... (19,891) (23,567) (74,742) (70,401) Decommissioning trust investments...................... (742) (304) (1,931) (1,013) Associated companies loans, net........................ (984) -- 76,374 -- Other.................................................. 153 (7,782) 2,061 (10,764) --------- --------- ---------- ---------- Net cash provided from (used for) investing activities ..................................... (21,464) (31,653) 1,762 (82,178) --------- --------- ---------- ---------- Net increase (decrease) in cash and cash equivalents...... (4,757) (185,704) (3,553) 30,168 Cash and cash equivalents at beginning of period.......... 6,027 247,296 4,823 31,424 --------- --------- ---------- ---------- Cash and cash equivalents at end of period................ $ 1,270 $ 61,592 $ 1,270 $ 61,592 ========= ========= ========== ========== <FN> The preceding Notes to Financial Statements as they relate to Jersey Power & Light Company are an integral part of these statements. </FN> </TABLE> 111
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 September 30, 2003, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2003 112
JERSEY CENTRAL POWER & LIGHT COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION 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. The "provider of last resort" (PLR) obligation known as Basic Generation Services (BGS) for customers who have not selected an alternative supplier had been removed from JCP&L as the result of the NJBPU approved auctions of those obligations. RESULTS OF OPERATIONS Earnings on common stock in the third quarter of 2003 decreased to $64.0 million from $103.5 million in the third quarter of 2002. For the first nine months of 2003, earnings on common stock were $74.6 million as compared to $199.7 million for the same period of 2002, as a result of non-cash charges aggregating $171.6 million ($103 million after tax) due to a rate case decision disallowing recovery of certain regulatory assets (see Regulatory Matters). Excluding the impact of those non-cash charges earnings on common stock were $167.2 million for the first nine months of 2003. Operating revenues decreased $36.8 million or 4.7% in the third quarter but increased $211.0 million or 12.2% in the first nine months of 2003, respectively, compared with the same periods in 2002. The lower revenues in the third quarter of 2003 compared to the previous year resulted from decreased wholesale revenues of $54.5 million. The milder summer weather adversely impacted the opportunities to sell in the wholesale market. The increase in revenues for the first nine months of the year was due to a $124.4 million increase in wholesale revenues and higher distribution deliveries. JCP&L's BGS obligation was transferred to external parties through a February 2002 auction process authorized by the New Jersey Board of Public Utilities (NJBPU). The auction removed JCP&L's BGS obligation for the period August 1, 2002 through July 31, 2003, and as a result, JCP&L has been selling all of its self-supplied energy (from non-utility generation power contracts and owned generation) into the wholesale market. The NJBPU subsequently approved the February 2003 BGS auction results for the period beginning August 1, 2003. The operating revenue changes also included increased retail generation sales revenue of $28.1 million and $39.4 million in the third quarter and first nine months of 2003, respectively, as compared to those periods in 2002. These revenue increases reflected higher unit prices which were partially offset by the effect of lower retail sales of 9.2% and 0.3%, respectively, in the third quarter and first nine months of 2003. Distribution deliveries increased by 1.6% in the third quarter of 2003 from the corresponding quarter of 2002. Lower unit prices in 2003 more than offset the impact of the increased volume and reduced revenues by $14.2 million. In addition, revenues reflect the impact of the net revenue decrease effective August 1, 2003, from the NJBPU's decision (see Regulatory Matters). Weather contributed to the $26.5 million (3.2%) increase in revenue from higher distribution deliveries to retail customers in the first nine months of 2003 compared to the same period last year. Colder temperatures early in the year resulted, in large part, in higher residential and commercial demand, which was partially offset by a decrease in industrial demand. Changes in distribution deliveries in the third quarter and the first nine months of 2003 compared with the same periods of 2002 are summarized in the following table: Changes in Kilowatt-Hour Deliveries Three Months Nine Months ----------------------------------------------------------------------- Increase (Decrease) Residential........................... 4.1% 5.5% Commercial............................ (2.6)% 5.2% Industrial............................ 3.7% (2.0)% ------------------------------------------------------------------------ Total Distribution Deliveries........... 1.6% 4.3% ======================================================================== Operating Expenses and Taxes Total operating expenses and taxes increased by $0.9 million in the third quarter and $336.4 million in the first nine months of 2003 compared to the same periods of 2002. These increases include the non-cash charges in the first nine months of 2003 for amounts disallowed in the JCP&L rate case decision (see Regulatory Matters), ($152.5 million charged to purchased power and $19.1 million charged to depreciation and amortization). The following table presents changes from the prior year by expense category. 113
Operating Expenses and Taxes - Changes Three Months Nine Months ---------------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................. $ (1.3) $ (1.0) Purchased power costs............................ (36.8) 346.8 Other operating costs............................ 60.6 70.0 ---------------------------------------------------------------------------- Total operation and maintenance expenses....... 22.5 415.8 Provision for depreciation and amortization...... 0.8 (5.2) General taxes.................................... 0.8 8.2 Income taxes..................................... (23.2) (82.4) ----------------------------------------------------------------------------- Net increase in operating expenses and taxes... $ 0.9 $336.4 ===========================================================================-- Purchased power costs decreased by $36.8 million in the third quarter compared to the prior year due to reduced energy requirements. Excluding the disallowed deferred energy costs of $152.5 million, purchased power increased $194.3 million in the first nine months of 2003 compared to the corresponding period of 2002. Increased kilowatt-hours purchased through two-party agreements and changes in the deferred energy and capacity costs were the primary contributors to the increase. Other operating expenses increased $60.6 million in the third quarter of 2003 and $70.0 million for the first nine months of 2003, compared to the same periods in 2002, due to higher pension and benefits costs, storm restoration expense and costs associated with an accelerated reliability plan within JCP&L's service territory. Excluding the disallowed costs discussed above, depreciation and amortization charges decreased by $12.2 million in the third quarter and $24.4 million in the first nine months of 2003, due to the cessation of amortization of regulatory assets related to the previously divested Oyster Creek Nuclear Generating Station, demand side management program deferrals and the reduction of depreciation rates on August 1, 2003 resulting from the NJBPU decision (see Regulatory Matters). General taxes increased $8.2 million in the first nine months of 2003, compared to the corresponding period in 2002, principally due to the absence of a $9 million energy assessment accrual reduction in the second quarter of 2002. Net Interest Charges Net interest charges decreased by $1.3 million in the third quarter of 2003 and $3.5 million in the first nine months compared with the same periods of 2002, reflecting debt redemptions since the beginning of the fourth quarter of 2002. Those decreases were partially offset by interest on $320 million of transition bonds issued in June 2002 (see Note 1) and $150 million of senior notes issued in May 2003 which were used for redeeming outstanding securities in the second and third quarters of 2003. CAPITAL RESOURCES AND LIQUIDITY JCP&L's cash requirements in 2003 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without materially increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities with affiliates will be used to manage working capital requirements. Over the next three years, JCP&L expects to meet its contractual obligations with cash from operations. Thereafter, JCP&L expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of September 30, 2003, JCP&L had $1.3 million of cash and cash equivalents, compared with $4.8 million as of December 31, 2002. The major sources of changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from operating activities during the third quarter and first nine months of 2003 compared to the corresponding periods of 2002 were as follows: Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------------- Operating Cash Flows 2003 2002 2003 2002 ------------------------------------------------------------------------- (In millions) Cash earnings (1)........ $ 108 $75 $ 256 $219 Working capital and other (101) 21 (199) (33) ------------------------------------------------------------------------- Total ............ $ 7 $96 $ 57 $186 ========================================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. 114
Net cash provided from operating activities decreased by $89 million in the third quarter of 2003 and $129 million in the first nine months of 2003 compared to the same periods of 2002. The third quarter decrease was due to a $122 million increase in funds used for working capital and other, partially offset by a $33 million increase in cash earnings. The change in working capital primarily reflects an $84 million change in accounts payable. Cash Flows From Financing Activities In the third quarter of 2003, net cash provided from financing activities of $9 million primarily reflected the issuance of $92 million of short-term debt and an $83 million repayment of long-term debt. In the third quarter of 2002, net cash used for financing activities totaled $250 million, due to redemptions ($192.5 million) and dividend payments of $57.7 million to FirstEnergy. As of September 30, 2003, JCP&L had approximately $1.3 million of cash and temporary investments and $287.9 million of short-term indebtedness. JCP&L may borrow from its affiliates on a short-term basis. JCP&L will not issue first mortgage bonds (FMB) other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of September 30, 2003. JCP&L had the capability to issue $666 million of additional senior notes based upon FMB collateral. Based upon applicable earnings coverage tests, JCP&L could issue a total of $783 million of preferred stock (assuming no additional debt was issued) as of September 30, 2003. Cash Flows From Investing Activities Net cash used for investing activities totaled $22 million in the third quarter and $2 million provided from investing activities in the first nine months of 2003, compared with net cash used of $32 million and $82 million in the third quarter and first nine months of 2002. Net cash used for investing in 2003 represented loan repayments from associated companies offset by expenditures for property additions. Net cash used in investing activities in 2002 were principally for property additions. During the fourth quarter of 2003, capital requirements for property additions are expected to be about $25 million. JCP&L has additional requirements of approximately $4 million for maturing long-term debt during the fourth quarter of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI, and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the securities of its electric utility operating companies. Fitch stated that the changes to the long-term ratings were "driven by the high debt leverage of the parent FE. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been vulnerable to unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable Outlook reflects the success of FE's recent common equity offering and management's focus on a relatively conservative integrated utility strategy." On October 27, 2003, Standard & Poors (S&P) stated that the `BBB' corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its utility subsidiaries remain on CreditWatch with negative implications. The ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's concerns regarding the potential impact of the August 14, 2003 blackout investigation on FirstEnergy's deleveraging strategy and its overall efforts to improve its credit profile. At that time, S&P also noted other challenges facing FirstEnergy, including the extended Davis-Besse outage; the recent U.S. District Court ruling regarding the Sammis Plant; reliability concerns in subsidiary JCP&L's service territory; and FirstEnergy's credibility with regulators and federal officials. S&P further noted several factors that could aid FirstEnergy in resolution of the CreditWatch, including strengthening its balance sheet. FirstEnergy directly addressed this concern through its recently completed common equity offering that raised approximately $935 million in net proceeds, 115
which was used to reduce bank debt. S&P described the equity offering as a "positive credit development" and also noted the recent renewal of FirstEnergy's $1 billion revolver facilities as a "favorable development, as it mitigates liquidity concerns." S&P also indicated that should various ongoing investigations into the causal factors of the August 14, 2003 blackout establish that the blackout resulted from no negligence or breach of compliance standards on FirstEnergy's part, the CreditWatch could be removed and the outlook returned to negative. S&P deemed a "stable" credit outlook unlikely until issues such as the restart of Davis-Besse are resolved and the potential effect of the litigation relating to the Sammis plant (the second trial is scheduled for April 2004) are known. Extension of the Ohio transition plan will be viewed as a positive development and will support an outlook revision to stable. On October 27, 2003, S&P also noted that the ratings on FirstEnergy and its subsidiaries incorporate such strengths as the ability to generate free cash flow, power generation contracted to its transmission and distribution subsidiaries through 2005, and the hedging of its short power position arising from its PLR obligation in Pennsylvania. S&P said that these strengths are offset by slower than anticipated reduction of FirstEnergy debt, remaining volume risks of PLR obligations, the extended outage at Davis-Besse, the unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty in Ohio. S&P also said that it now views FirstEnergy's liquidity position as average, following FirstEnergy's renewal of its $1 billion credit facilities. 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 third quarter and first nine months of 2003 is summarized in the following table: <TABLE> <CAPTION> Three Months Ended Nine Months Ended Increase (Decrease) in the Fair Value September 30, 2003 September 30, 2003 -------------------------- -------------------------- of Commodity Derivative Contracts Non-Hedge Hedge Total Non-Hedge Hedge Total --------- ----- ----- --------- ----- ----- (In millions) Change in the Fair Value of Commodity Derivative Contracts <S> <C> <C> <C> <C> <C> <C> Net asset at beginning of period....................... $12.9 $ (0.1) $12.8 $ 8.7 $(0.1) $ 8.6 New contract value when entered........................ -- -- -- -- -- -- Changes in value of existing contracts................. (0.1) -- (0.1) 4.0 -- 4.0 Change in techniques/assumptions....................... 2.3 -- 2.3 2.3 -- 2.3 Settled contracts...................................... -- 0.1 0.1 0.1 0.1 0.2 - ------------------------------------------------------- ------------------------- ------------------------ Net Assets - Derivative Contracts at end of period (1). $15.1 $ -- $15.1 $15.1 $-- $15.1 ======================================================= ========================= ======================== Impact of Changes in Commodity Derivative Contracts (2) Income Statement Effects (Pre-Tax)..................... $-- $ -- $ -- $ -- $-- $-- Balance Sheet Effects: Other Comprehensive Income (Pre-Tax)................ $-- $ 0.1 $ 0.1 $ -- $ 0.1 $ 0.1 Regulatory Liability................................ $ 2.2 $ -- $ 2.2 $ 6.4 $-- $ 6.4 <FN> (1) Represents contracts which are offset by a regulatory liability. (2) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. </FN> </TABLE> Derivatives included on the Consolidated Balance Sheet as of September 30, 2003: Non-Hedge Hedge Total ---------------------------------------------------------------------- (In millions) Current- Other Assets.................. $-- $ -- $-- Other Liabilities............. -- -- -- Non-Current- Other Deferred Charges........ 15.1 -- 15.1 Other Deferred Credits........ -- -- -- ------------------------------------------------------------------- Net Assets.................... $15.1 $ -- $15.1 ====================================================================== 116
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: <TABLE> <CAPTION> Source of Information - - Fair Value by Contract Year 2003(1) 2004 2005 2006 Thereafter Total - ---------------------------------------------------------------------------------------------------------- (In millions) <S> <C> <C> <C> <C> <C> <C> Prices based on external sources(2)... $0.3 $2.1 $2.3 $-- $-- $ 4.7 Prices based on models................ -- -- -- 2.4 8.0 10.4 - ----------------------------------------------------------------------------------------------------------- Total(3).......................... $0.3 $2.1 $2.3 $2.4 $8.0 $15.1 =========================================================================================================== <FN> (1) For the last quarter of 2003. (2) Broker quote sheets. (3) Represents an embedded option that is offset by a regulatory liability and does not affect earnings. </FN> </TABLE> JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of September 30, 2003. Equity Price Risk Included in JCP&L's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $61 million and $52 million as of September 30, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of September 30, 2003. OUTLOOK Beginning in 1999, all of JCP&L's customers were able to select alternative energy suppliers. JCP&L continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. To support customer choice, rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs. Regulatory assets are costs which have been authorized by the NJBPU and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of JCP&L's regulatory assets are expected to continue to be recovered under the provisions of the regulatory proceedings discussed below. JCP&L's regulatory assets totaled $2.9 billion and $3.2 billion as of September 30, 2003 and December 31, 2002, respectively. Regulatory Matters Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L submitted two rate filings with the NJBPU in August 2002. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current market transition charge (MTC) and societal benefits charge (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 percent on JCP&L's rate base for 6 to 12 months. During that period, JCP&L will initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75 percent or decrease it to 9.25 percent, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The 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 charge. 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 nine months ended September 30, 2003, aggregating $172 million ($103 million net of tax) consisting of the $153 million deferred energy costs and other regulatory assets. JCP&L filed a 117
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, which is expected in the fourth quarter of 2003. Environmental Matters JCP&L has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2003, based on estimates of the total costs of cleanup, JCP&L's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered through the SBC. JCP&L has accrued liabilities aggregating approximately $47.9 million as of September 30, 2003. JCP&L does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against us, the most significant of which are described above and below. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including JCP&L. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. In July 1999, two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court against JCP&L and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in its service territory. In May 2001, the court denied without prejudice JCP&L's motion seeking decertification of the class. Discovery continues in the class action, but no trial date has been set. In October 2001, the court held argument on the plaintiffs' motion for partial summary judgment, which contends that JCP&L is bound to several findings of the NJBPU investigation. The plaintiffs' motion was denied by the Court in November 2001 and the plaintiffs' motion to file an appeal of this decision was denied by the New Jersey Appellate Division. JCP&L has also filed a motion for partial summary judgment that is currently pending before the Superior Court. JCP&L is unable to predict the outcome of these matters. A series of unexpected faults in the three transmission lines triggered a series of outages for approximately 34,000 customers from July 5-8, 2003. The NJBPU has launched an investigation into the causes of the outages, and JCP&L has filed an incident report with the NJBPU, detailing the timeline and causes for the outages. JCP&L has committed to accelerate $60 million in transmission system improvements. Additionally, JCP&L sited ten emergency generators at strategic locations within a few days of the outage. Without admitting liability, JCP&L has established a streamlined procedure to address customers' damage claims. SIGNIFICANT ACCOUNTING POLICIES JCP&L prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of JCP&L's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. JCP&L's more significant accounting policies are described below. Purchase Accounting The merger between FirstEnergy and GPU was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities were based primarily on estimates. The adjustments reflected in JCP&L's records, which were finalized in the fourth quarter of 2002, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory 118
redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," JCP&L evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. 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 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 indicated. JCP&L's annual review was completed in the third quarter of 2003, with no impairment of goodwill indicated. The forecasts used in JCP&L's evaluation of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on JCP&L's future evaluations of goodwill. As of September 30, 2003, JCP&L had recorded goodwill of approximately $2.0 billion related to the merger. Regulatory Accounting JCP&L is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine JCP&L is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in New Jersey, a significant amount of regulatory assets have been recorded - $2.9 billion as of September 30, 2003. 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 JCP&L's normal operations, it enters into commodity contracts which increase the impact of derivative accounting judgments. Revenue Recognition JCP&L follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not 119
reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy is not required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," JCP&L periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, JCP&L recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). RECENTLY ISSUED ACCOUNTING STANDARDS FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". This Interpretation requires the consolidation of a variable interest entity (VIE) by an enterprise if that enterprise either absorbs a majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns as a result of ownership, contractual or other financial interests in the VIE. Currently, entities are generally consolidated by an enterprise that has a controlling financial interest through ownership of a majority voting interest in the entity. FIN 46 defines a VIE as an entity in which equity investors do not have the characteristics of a controlling financial interest nor have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. VIE's created after January 31, 2003, are immediately subject to the provisions of FIN 46. The FASB recently deferred implementation of FIN 46 for VIE's created before February 1, 2003, until the first reporting period ending after December 15, 2003 (JCP&L's quarter ending December 31, 2003.) The adoption of FIN 46 for variable interests created after January 31, 2003 did not have an impact on JCP&L's financial statements. We are continuing to review the provisions of FIN 46 to determine its impact, if any, on future reporting periods with respect to interests in VIE's created prior to February 1, 2003, and do not currently anticipate that adoption will result in any material accounting or disclosure requirements. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS 133 for decisions made by the Derivative Implementation Group, as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for quarters which began prior to June 15, 2003, that continue to be applied based on their original effective dates. Adoption of SFAS 149 did not have a material impact on JCP&L's financial statements. 120
DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to JCP&L's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence of a general index, such as the Consumer Price Index, in a contract would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. JCP&L is currently assessing the new guidance but does not anticipate any material impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus on Issue No. 01-08 regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus is to be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. The adoption of this consensus as of July 1, 2003 did not impact JCP&L's financial statements. 121
<TABLE> <CAPTION> METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- --------------------- 2003 2002 2003 2002 -------- -------- -------- -------- (In thousands) <S> <C> <C> <C> <C> OPERATING REVENUES........................................ $261,756 $281,540 $730,671 $767,333 -------- -------- -------- -------- OPERATING EXPENSES AND TAXES: Purchased power........................................ 159,968 201,320 425,116 483,756 Other operating costs.................................. 41,660 24,372 109,240 86,947 -------- -------- -------- -------- Total operation and maintenance expenses........... 201,628 225,692 534,356 570,703 Provision for depreciation and amortization............ 18,508 22,022 67,745 52,360 General taxes.......................................... 18,406 19,237 50,804 50,964 Income taxes........................................... 4,153 988 16,136 22,886 -------- -------- -------- -------- Total operating expenses and taxes................. 242,695 267,939 669,041 696,913 -------- -------- -------- -------- OPERATING INCOME.......................................... 19,061 13,601 61,630 70,420 OTHER INCOME.............................................. 5,357 5,884 15,832 16,471 -------- -------- -------- -------- INCOME BEFORE NET INTEREST CHARGES........................ 24,418 19,485 77,462 86,891 -------- -------- -------- -------- NET INTEREST CHARGES: Interest on long-term debt............................. 8,501 10,054 28,382 30,736 Allowance for borrowed funds used during construction.. (94) (234) (252) (798) Deferred interest...................................... (192) (167) (1,187) (402) Other interest expense................................. 2,521 854 3,386 2,025 Subsidiary's preferred stock dividend requirements..... -- 1,890 3,779 5,669 -------- -------- -------- -------- Net interest charges............................... 10,736 12,397 34,108 37,230 -------- -------- -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE ................................................... 13,682 7,088 43,354 49,661 Cumulative effect of accounting change (net of income taxes of $154,000) (Note 5)............................ -- -- 217 -- -------- -------- -------- -------- NET INCOME................................................ $ 13,682 $ 7,088 $ 43,571 $ 49,661 ======== ======== ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements. </FN> </TABLE> 122
<TABLE> <CAPTION> METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (In thousands) ASSETS ------ <S> <C> <C> UTILITY PLANT: In service................................................................ $1,825,650 $1,620,613 Less--Accumulated provision for depreciation.............................. 762,454 547,925 ---------- ---------- 1,063,196 1,072,688 Construction work in progress.............................................. 20,068 16,078 ---------- ---------- 1,083,264 1,088,766 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts...................................... 176,848 155,690 Long-term notes receivable from associated companies...................... 9,974 12,418 Other..................................................................... 31,538 19,206 ---------- ---------- 218,360 187,314 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 142 15,685 Receivables- Customers (less accumulated provisions of $5,061,000 and $4,810,000 respectively, for uncollectible accounts)............................. 117,722 120,868 Associated companies.................................................... 57,839 23,219 Other................................................................... 19,802 18,235 Notes receivable from associated companies................................ 10,010 -- Material and supplies, at average cost.................................... 145 -- Prepayments and other..................................................... 12,231 9,731 ---------- ---------- 217,891 187,738 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 1,059,756 1,179,125 Goodwill.................................................................. 885,832 885,832 Other..................................................................... 38,222 36,030 ---------- ---------- 1,983,810 2,100,987 ---------- ---------- $3,503,325 $3,564,805 ========== ========== </TABLE> 123
<TABLE> <CAPTION> METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ <S> <C> <C> CAPITALIZATION: Common stockholder's equity- Common stock, without par value, authorized 900,000 shares - 859,500 shares outstanding............................................ $1,297,784 $1,297,784 Accumulated other comprehensive loss.................................... (36,414) (39) Retained earnings....................................................... 34,411 17,841 ---------- ---------- Total common stockholder's equity................................... 1,295,781 1,315,586 Company-obligated mandatorily redeemable preferred securities (Note 5).... -- 92,409 Long-term debt and other long-term obligations- Company-obligated mandatorily redeemable preferred securities (Note 5).. 92,566 -- Other................................................................... 569,105 538,790 ---------- ---------- 1,957,452 1,946,785 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 40,469 60,467 Accounts payable- Associated companies.................................................... 60,222 56,861 Other................................................................... 34,457 28,583 Notes payable to associated companies..................................... 56,256 88,299 Accrued taxes............................................................. 3,636 16,096 Accrued interest.......................................................... 8,497 16,448 Other..................................................................... 20,063 11,690 ---------- ---------- 223,600 278,444 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes......................................... 260,123 316,757 Accumulated deferred investment tax credits............................... 11,903 12,518 Power purchase contract loss liability.................................... 614,608 660,507 Nuclear fuel disposal costs............................................... 37,845 37,541 Asset retirement obligation............................................... 207,139 -- Nuclear decommissioning costs............................................. -- 270,611 Retirement benefits....................................................... 119,738 1,354 Other..................................................................... 70,917 40,288 ---------- ---------- 1,322,273 1,339,576 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $3,503,325 $3,564,805 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets. </FN> </TABLE> 124
<TABLE> <CAPTION> METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- --------------------- 2003 2002 2003 2002 -------- -------- -------- -------- (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 13,682 $ 7,088 $ 43,571 $ 49,661 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 18,508 22,022 67,745 52,360 Deferred costs, net................................ 5,621 7,678 (7,857) (1,733) Deferred income taxes, net......................... (315) 2,111 9,349 14,301 Amortization of investment tax credits............. (205) (212) (615) (636) Accrued retirement benefit obligation.............. 3,620 25 7,144 38 Accrued compensation, net.......................... (120) (352) 6,207 (2,389) Cumulative effect of accounting change (Note 5).... -- -- (371) -- Receivables........................................ 11,953 (3,494) 2,007 (17,302) Materials and supplies............................. (6) -- (145) -- Accounts payable................................... (89,944) (26,567) (5,647) (29,492) Accrued taxes...................................... 214 5 (12,460) (5,084) Accrued interest................................... (4,161) (7,063) (7,951) (6,627) Prepayments and other current assets............... 16,136 16,088 (2,500) 4,662 Other.............................................. (11,300) (18,365) (30,201) (38,592) -------- -------- -------- -------- Net cash provided from (used for) operating activities ..................................... (36,317) (1,036) 68,276 19,167 -------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt....................................... -- -- 247,696 49,750 Short-term borrowings, net........................... 35,591 60,628 -- 59,769 Redemptions and Repayments- Long-term debt....................................... (32) (30,000) (230,467) (60,000) Short-term borrowings, net........................... -- -- (32,043) -- Dividend Payments- Common stock......................................... (7,000) -- (27,000) (30,000) -------- -------- -------- -------- Net cash provided from (used for) financing activities ..................................... 28,559 30,628 (41,814) 19,519 -------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... (8,382) (11,209) (28,284) (31,996) Contributions to nuclear decommissioning trusts........ (2,371) (2,371) (7,112) (10,358) Associated companies loans, net........................ 17,144 -- (7,566) -- Other.................................................. 1,179 (20) 957 (279) -------- -------- -------- -------- Net cash provided from (used for) investing activities ..................................... 7,570 (13,600) (42,005) (42,633) -------- -------- -------- -------- Net increase (decrease) in cash and cash equivalents...... (188) 15,992 (15,543) (3,947) Cash and cash equivalents at beginning of period.......... 330 5,335 15,685 25,274 -------- -------- -------- -------- Cash and cash equivalents at end of period................ $ 142 $ 21,327 $ 142 $ 21,327 ======== ======== ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements. </FN> </TABLE> 125
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 September 30, 2003, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2003 126
METROPOLITAN EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Met-Ed provides regulated transmission and distribution services in eastern and south central Pennsylvania. Pennsylvania customers are able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. Met-Ed's regulatory plan required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Met-Ed continues to deliver power to homes and businesses through its existing distribution system and maintains provider of last resort (PLR) obligations to customers who elect to retain Met-Ed as their power supplier. RESULTS OF OPERATIONS Net income in the third quarter of 2003 increased to $13.7 million from $7.1 million in the third quarter of 2002. During the first nine months of 2003, net income decreased to $43.6 million from $49.7 million in the first nine months of 2002. Net income in the first nine months of 2003 included an after-tax credit of $0.2 million from the cumulative effect of an accounting change due to the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $43.4 million in the first nine months of 2003 compared with $49.7 million in the corresponding period of 2002. The higher earnings in the third quarter of 2003 reflected lower depreciation and amortization charges and reduced purchased power costs that were partially offset by lower operating revenues and higher other operating costs. Comparing the first nine month periods, the effect of higher depreciation and amortization charges and lower operating revenues, were partially offset by lower purchased power costs in the first nine months of 2003. Operating revenues decreased by $19.8 million or 7.0% in the third quarter of 2003 compared with the same period of 2002 due to decreased distribution deliveries, as well as reduced sales to the wholesale market. Retail distribution deliveries decreased by 4.0% and reduced revenues by $6.4 million, as a result of cooler temperatures in the third quarter of 2003 compared to the same period last year. Wholesale revenue decreased by $10.3 million, which reflected lower sales to affiliated companies and to the wholesale market. Operating revenues decreased by $36.7 million or 4.8% in the first nine months of 2003 compared with the first nine months of 2002. Retail generation kilowatt-hour sales decreased by 2.2%, which consisted of lower commercial (4.0%) and industrial (10.0%) sales, and higher residential sales (3.3%) - producing decreased revenues of $9.0 million. Wholesale sales revenues decreased $25.7 million principally due to a reduction in kilowatt-hour sales to affiliated companies and to the wholesale market. Distribution deliveries were nearly flat in the first nine months of 2003 compared with the same period of 2002. Distribution deliveries benefited from higher residential demand (3.2%), due in large part to colder temperatures in the first quarter of 2003, which were partially offset by decreases in commercial (1.3%) and industrial (0.3%) demand from the continued effect of a sluggish, but improving, economy. Changes in electric generation sales and distribution deliveries in the third quarter and first nine months of 2003 from the same periods of 2002 are summarized in the following table: Changes in Kilowatt-Hour Sales Three Months Nine Months ---------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. 0.6% (2.2)% Wholesale............................... (100.0)% (100.9)% ---------------------------------------------------------------------- Total Electric Generation Sales........... (7.6)% (11.1)% ====================================================================== Distribution Deliveries: Residential............................. (8.0)% 3.2% Commercial.............................. (12.1)% (1.3)% Industrial.............................. 14.0% (0.3)% ---------------------------------------------------------------------- Total Distribution Deliveries............. (4.0)% 0.7% ---------------------------------------------------------------------- Operating Expenses and Taxes Total operating expenses and taxes decreased $25.2 million in the third quarter and $27.9 million in the first nine months of 2003 compared to the same periods of 2002, primarily due to lower purchased power costs for both periods. Lower depreciation and amortization charges that were partially offset by higher other operating costs also contributed to the decrease in operating expenses in the third quarter of 2003. The lower purchased power costs during the first nine months of 2003 were partially offset by higher depreciation and amortization costs, as well as higher other operating costs. The following table presents changes from the prior year by expense category. 127
Operating Expenses and Taxes - Changes Three Months Nine Months Increase (Decrease) (In millions) Purchased power costs........................ $(41.4) $(58.6) Other operating costs........................ 17.3 22.3 ------------------------------------------------------------------------- Total operation and maintenance expenses.. (24.1) (36.3) Provision for depreciation and amortization.. (3.5) 15.4 General taxes................................ (0.8) (0.2) Income taxes................................. 3.2 (6.8) ------------------------------------------------------------------------- Net decrease in operating expenses and taxes $(25.2) $(27.9) ========================================================================= Lower purchased power costs in the third quarter and first nine months of 2003, compared with the same periods of 2002, were primarily attributed to lower unit costs in the third quarter of 2003 and fewer kilowatt-hours required for customer needs during the first nine months of 2003. Lower depreciation and amortization charges in the third quarter of 2003 compared to the same period in 2002, reflected lower depreciation expense on a reduced asset base and lower amortization of regulatory assets being recovered through the competitive transition charge (CTC). The increase in depreciation and amortization charges for the first nine months of 2003 compared to the same period in 2002, reflected increases in amortization of regulatory assets being recovered through the competitive transition charge (CTC). Other operating costs increased by $17.3 million in the three months and $22.3 million in the nine months ended September 30, 2003, compared with the same periods of 2002, primarily due to higher employee benefit costs and costs to restore customer service resulting from significant storm activity. Net Interest Charges Net interest charges decreased by $1.7 million in the third quarter of 2003 and $3.1 million in the first nine months of 2003 from the same periods last year. The decreases reflect the refinancing of higher rate debt in the second quarter of 2003 through the issuance of $250 million of new senior notes in March 2003 and the redemption of $40 million and $20 million of notes in the first and second quarters of 2003, respectively. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Met-Ed recorded an after-tax credit to net income of approximately $0.2 million. Met-Ed identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $186 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $186 million. The asset retirement obligation (ARO) liability at the date of adoption was $198 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, Met-Ed had recorded decommissioning liabilities of $260 million. Met-Ed expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, Met-Ed recognized a regulatory liability of $61 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the liabilities was a $0.4 million increase to income, or $0.2 million net of income taxes. CAPITAL RESOURCES AND LIQUIDITY Met-Ed's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and optional debt redemptions are expected to be met without materially 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 September 30, 2003, Met-Ed had $0.1 million of cash and cash equivalents compared with $15.7 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from (used for) operating activities during the third quarter and first nine months of 2003, compared with corresponding periods of 2002 were as follows: 128
Three Months Ended Nine Months Ended September 30, September 30, ------------------ ------------------ Operating Cash Flows 2003 2002 2003 2002 ----------------------------------------------------------------------- (In millions) Cash earnings (1)....... $ 41 $ 38 $ 125 $111 Working capital and other (77) (39) (57) (92) ----------------------------------------------------------------------- Total................... $(36) $ (1) $ 68 $ 19 ======================================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash used for operating activities decreased $35 million in the third quarter of 2003 compared to the same period in 2002 due to a $38 million increase in working capital and other requirements (primarily from changes in accounts payable) which was partially offset by an increase in cash earnings. Net cash provided from operating activities increased $49 million in the first nine months of 2003 compared with the same period in 2002. The increase consisted of a $14 million increase in cash earnings and a $35 million decrease in working capital and other requirements (primarily due to accounts payable change). Cash Flows From Financing Activities In the third quarter of 2003, net cash provided from financing activities of $29 million reflected the increase of $36 million of short-term debt, partially offset by a $7 million dividend payment to FirstEnergy. In the third quarter of 2002, net cash provided from financing activities totaled $31 million, due to the increase of $61 million of short-term debt, partially offset by the redemption of $30 million of medium term notes. As of September 30, 2003, Met-Ed had approximately $10.2 million of cash and temporary investments, including $10 million of notes receivable from associated companies and approximately $56.3 million of short-term indebtedness. Met-Ed may borrow from its affiliates on a short-term basis. Met-Ed will not issue first mortgage bonds (FMB) other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of September 30, 2003, Met-Ed had the capability to issue $152 million of additional senior notes based upon FMB collateral. Met-Ed had no restrictions on the issuance of preferred stock. Cash Flows From Investing Activities Net cash provided from investing activities totaled $8 million in the third quarter, and net cash used for investing activities totaled $42 in the first nine months of 2003. The net cash flows provided from investing activities in the third quarter of 2003 resulted from the repayment of borrowings by associated companies, partially offset by property additions and decommissioning trust investments. The net cash flows used for investing activities during the first nine months of 2003 resulted from property additions, decommissioning trust investments, and loans to associated companies. Expenditures for property additions primarily support Met-Ed's energy delivery operations. In the third quarter and first nine months of 2002, net cash flows used for investing activities totaled $14 million and $43 million, respectively, principally due to property additions. During the fourth quarter of 2003, capital requirements for property additions are expected to be about $9 million. Met-Ed has no additional requirements for maturing long-term debt during the remainder of 2003. The capital requirements are expected to be satisfied from internal cash and short-term credit arrangements. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior secured, senior unsecured, and preferred stock ratings of Met-Ed. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the securities of its electric utility operating companies. Fitch stated that the changes to the long-term ratings were "driven by the high debt leverage of the parent FE. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been vulnerable to unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable Outlook reflects the success of FE's recent common equity offering and management's focus on a relatively conservative integrated utility strategy." 129
On October 27, 2003, Standard & Poors (S&P) stated that the `BBB' corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy's and its utility subsidiaries remain on CreditWatch with negative implications. The ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's concerns regarding the potential impact of August 14, 2003 blackout investigation on FirstEnergy's deleveraging strategy and its overall efforts to improve its credit profile. At that time, S&P also noted other challenges facing FirstEnergy, including the extended Davis-Besse outage; the recent U.S. District Court ruling regarding the Sammis Plant; reliability concerns in subsidiary JCP&L's service territory; and FirstEnergy's credibility with regulators and federal officials. S&P further noted several factors that could aid FirstEnergy in resolution of the CreditWatch, including strengthening its balance sheet. FirstEnergy directly addressed this concern through its recently completed common equity offering that raised approximately $935 million in net proceeds, which was used to reduce bank debt. S&P described the equity offering as a "positive credit development" and also noted the recent renewal of FirstEnergy's $1 billion revolver facilities as a "favorable development, as it mitigates liquidity concerns." S&P also indicated that should various ongoing investigations into the causal factors of the August 14, 2003 blackout establish that the blackout resulted from no negligence or breach of compliance standards on FirstEnergy's part, the CreditWatch could be removed and the outlook returned to negative. S&P deemed a "stable" credit outlook unlikely until issues such as the restart of Davis-Besse are resolved and the potential effect of the litigation relating to the Sammis plant (the second trial is scheduled for April 2004) are known. Extension of the Ohio transition plan will be viewed as a positive development and will support an outlook revision to stable. In its October 27, 2003, comments, S&P also noted that the ratings on FirstEnergy and its subsidiaries incorporate such strengths as the ability to generate free cash flow, power generation contracted to its transmission and distribution subsidiaries through 2005, and the hedging of its short power position arising from its PLR obligation in Pennsylvania. S&P said that these strengths are offset by slower than anticipated reduction of FirstEnergy debt, remaining volume risks of PLR obligations, the extended outage at Davis-Besse, the unfavorable outcome of the New Jersey rate proceeding and regulatory uncertainty in Ohio. S&P also said that it now views FirstEnergy's liquidity position as average, following FirstEnergy's renewal of its $1 billion credit facilities. 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 third quarter and the first nine months of 2003 is summarized in the following table: <TABLE> <CAPTION> Increase (Decrease) in the Fair Value Three Months Ended Nine Months Ended of Commodity Derivative Contracts September 30, 2003 September 30, 2003 - ----------------------------------------------------------------------------------------------------------------------------- Non-Hedge Hedge Total Non-Hedge Hedge Total --------- ----- ----- --------- ----- ----- (In millions) Change in the Fair Value of Commodity Derivative Contracts <S> <C> <C> <C> <C> <C> <C> Outstanding net asset at beginning of period........... $ 25.9 $ -- $25.9 $17.4 $ 0.1 $17.5 New contract value when entered........................ -- -- -- -- -- -- Additions/Increase in value of existing contracts...... (0.4) -- (0.4) 8.1 -- 8.1 Change in techniques/assumptions....................... 4.6 -- 4.6 4.6 -- 4.6 Settled contracts...................................... -- -- -- -- (0.1) (0.1) - -------------------------------------------------------------- ------------------------- ----------------------------- Net Assets - Derivative Contracts as of September 30, 2003 (1) $ 30.1 $ -- $30.1 $30.1 $ -- $30.1 ============================================================== ========================= ============================= Impact of Changes in Commodity Derivative Contracts (2) Income Statement Effects (Pre-Tax)..................... $ (0.1) $ -- $(0.1) $ -- $ -- $ -- Balance Sheet Effects: Other Comprehensive Income (Pre-Tax)................ $ -- $ -- $ -- $ -- $(0.1) $(0.1) Regulatory Liability................................ $ 4.3 $ -- $ 4.3 $12.7 $ -- $12.7 (1) Includes $29.9 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. </TABLE> 130
Derivatives included on the Consolidated Balance Sheet as of September 30, 2003: Non-Hedge Hedge Total ------------------------------------------------------------------- (In millions) Current- Other Assets.................. $-- $ -- $ -- Other Liabilities............. -- -- -- Non-Current- Other Deferred Charges........ 30.1 -- 30.1 Other Deferred Credits........ -- -- -- ------------------------------------------------------------------- Net Assets.................... $30.1 $ -- $30.1 =================================================================== The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, 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: <TABLE> <CAPTION> Source of Information - - Fair Value by Contract Year 2003(1) 2004 2005 2006 Thereafter Total - ----------------------------------------------------------------------------------------------------------- (In millions) <S> <C> <C> <C> <C> <C> <C> Prices based on external sources(2)... $0.6 $4.1 $4.5 $-- $ -- $ 9.2 Prices based on models................ -- -- -- 4.9 16.0 20.9 - ----------------------------------------------------------------------------------------------------------- Total(3).......................... $0.6 $4.1 $4.5 $4.9 $16.0 $30.1 =========================================================================================================== </TABLE> (1) For the last quarter of 2003. (2) Broker quote sheets. (3) Includes $29.9 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 September 30, 2003. Equity Price Risk Included in Met-Ed's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $101 million and $81 million as of September 30, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $10 million reduction in fair value as of June 30, 2003. OUTLOOK Beginning in 1999, all of Met-Ed's customers were able to select alternative energy suppliers. Met-Ed continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. The Pennsylvania Public Utility Commission (PPUC) authorized Met-Ed's rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. Met-Ed has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as its PLR obligation. Regulatory assets are costs which have been authorized by the PPUC and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of Met-Ed's regulatory assets are expected to continue to be recovered under the provisions of the regulatory plan as discussed below. Met-Ed's regulatory assets totaled $1.1 billion and $1.2 billion as of September 30, 2003 and December 31, 2002, respectively. Regulatory Matters Effective September 1, 2002, Met-Ed assigned its PLR responsibility to its unregulated supply affiliate, FirstEnergy Solutions Corp. (FES), through a wholesale power sale agreement which expires in December 2003 and may be 131
extended for each successive calendar year. Under the terms of the wholesale agreement, FES assumed the supply obligation, and the energy supply profit and loss risk, for the portion of power supply requirements that Met-Ed does not self-supply under its non-utility generation (NUG) contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces its 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 to FES. Met-Ed is authorized to continue deferring differences between NUG contract costs and current market prices. On April 2, 2003, the PPUC remanded the issue relating to merger savings to the Office of Administrative Law 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 Administrative Law Judge 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 their tariffs to become effective October 24, 2003. On October 8, 2003, Met-Ed filed a petition for clarification relating to the October 2 order on two issues: to establish the end of June 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 findings would not impair Met-Ed's rights to recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceeding) 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 request 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 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. Met-Ed is considering filing an appeal to the Commonwealth Court on the PPUC orders as well. Environmental Matters Met-Ed has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2003, based on estimates of the total costs of cleanup, Met-Ed's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Met-Ed has accrued liabilities aggregating approximately $0.2 million as of September 30, 2003. Met-Ed does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against Met-Ed, the most significant of which are described above. SIGNIFICANT ACCOUNTING POLICIES Met-Ed prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect its financial results. All of its assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. Met-Ed's more significant accounting policies are described below. Purchase Accounting The merger between FirstEnergy and GPU was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired 132
assets and assumed liabilities were based primarily on estimates. The adjustments reflected in Met-Ed's records, which were finalized in the fourth quarter of 2002, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," Met-Ed evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. 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 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 of goodwill indicated. The forecasts used in Met-Ed's evaluation of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill of September 30, 2003, Met-Ed had recorded goodwill of approximately $885.8 million related to the merger. Regulatory Accounting Met-Ed is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine it is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded - $1.1 billion as of September 30, 2003. 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 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 Met-Ed's normal operations, it enters into commodity contracts which increase the impact of derivative accounting judgments. Revenue Recognition Met-Ed follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors 133
may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy is not required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," Met-Ed periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, Met-Ed would recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). RECENTLY ISSUED ACCOUNTING STANDARDS FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". This Interpretation requires the consolidation of a variable interest entity (VIE) by an enterprise if that enterprise either absorbs a majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns as a result of ownership, contractual or other financial interests in the VIE. Currently, entities are generally consolidated by an enterprise that has a controlling financial interest through ownership of a majority voting interest in the entity. FIN 46 defines a VIE as an entity in which equity investors do not have the characteristics of a controlling financial interest nor have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. VIE's created after January 31, 2003, are immediately subject to the provisions of FIN 46. The FASB recently deferred implementation of FIN 46 for VIE's created before February 1, 2003, until the first reporting period ending after December 15, 2003 (Met-Ed's quarter ending December 31, 2003.) As described in Note 1, the consolidated financial statements of Met-Ed include a statutory business trust that sold trust-preferred securities in which Met-Ed is not the primary beneficiary. Pending further guidance from the FASB that would indicate otherwise, this entity may not be consolidated in Met-Ed's financial statements as of December 31, 2003. The deconsolidation would result in an increase in total assets and liabilities of approximately $3.1 million for the investment in the trust. The FASB continues to provide additional guidance on implementing FIN 46 and recently proposed modifications and clarifications with a comment period ending December 1, 2003. As this guidance is finalized, Met-Ed will continue to assess the accounting and disclosure impact of FIN 46 with respect to potential VIE's. 134
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS 133 for decisions made by the Derivative Implementation Group (DIG), as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for reporting periods beginning before June 15, 2003, that continue to be applied based on their original effective dates. Adoption of SFAS 149 did not have a material impact on Met-Ed's financial statements. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the beginning of the first interim period beginning after June 15, 2003 (Met-Ed's third quarter of 2003) for all other financial instruments. Upon adoption of SFAS 150, effective July 1, 2003, company-obligated mandatorily redeemable preferred securities of $92.6 million were reclassified and included in long-term debt as of September 30, 2003. As required by SFAS 150, the preferred securities subject to mandatory redemption were not restated as long-term debt on the December 31, 2002 balance sheet. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to Met-Ed's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence of a general index, such as the Consumer Price Index, in a contract would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. Met-Ed is currently assessing the new guidance but does not anticipate any material impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus on Issue No. 01-08, regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus is to be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. The adoption of this consensus as of July 1, 2003 did not impact Met-Ed's financial statements. 135
<TABLE> <CAPTION> PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2003 2002 2003 2002 (In thousands) <S> <C> <C> <C> <C> OPERATING REVENUES........................................ $242,960 $269,359 $729,762 $749,755 -------- -------- -------- -------- OPERATING EXPENSES AND TAXES: Purchased power........................................ 153,440 191,756 467,225 480,608 Other operating costs.................................. 48,168 27,759 125,196 99,977 -------- -------- -------- -------- Total operation and maintenance expenses........... 201,608 219,515 592,421 580,585 Provision for depreciation and amortization............ 10,982 16,098 38,358 45,743 General taxes.......................................... 17,032 17,744 48,630 47,200 Income taxes........................................... 862 3,040 9,316 18,839 -------- -------- -------- -------- Total operating expenses and taxes................. 230,484 256,397 688,725 692,367 -------- -------- -------- -------- OPERATING INCOME.......................................... 12,476 12,962 41,037 57,388 OTHER INCOME.............................................. 545 1,067 887 2,154 -------- -------- -------- -------- INCOME BEFORE NET INTEREST CHARGES........................ 13,021 14,029 41,924 59,542 -------- -------- -------- -------- NET INTEREST CHARGES: Interest on long-term debt............................. 7,432 7,796 22,123 24,124 Allowance for borrowed funds used during construction.. (77) 84 (257) (199) Deferred interest...................................... (380) (869) (2,525) (2,311) Other interest expense................................. 2,071 684 2,333 2,123 Subsidiary's preferred stock dividend requirements..... -- 1,888 3,777 5,665 -------- -------- -------- -------- Net interest charges............................... 9,046 9,583 25,451 29,402 -------- -------- -------- -------- Income before cumulative effect of accounting change...... 3,975 4,446 16,473 30,140 Cumulative effect of accounting change (net of income taxes of $777,000) (Note 5)............................. -- -- 1,096 -- -------- -------- -------- -------- NET INCOME................................................ $ 3,975 $ 4,446 $ 17,569 $ 30,140 ======== ======== ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements. </FN> </TABLE> 136
<TABLE> <CAPTION> PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ----------- ------------ (In thousands) ASSETS ------ <S> <C> <C> UTILITY PLANT: In service................................................................ $1,956,623 $1,844,999 Less--Accumulated provision for depreciation.............................. 773,485 647,581 ---------- ---------- 1,183,138 1,197,418 Construction work in progress- Electric plant.......................................................... 24,448 19,200 ---------- ---------- 1,207,586 1,216,618 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Non-utility generation trusts............................................. 3,840 109,881 Nuclear plant decommissioning trusts...................................... 95,894 88,818 Long-term notes receivable from associated companies...................... 14,905 15,515 Other..................................................................... 15,497 9,425 ---------- ---------- 130,136 223,639 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents................................................. 84 10,310 Receivables- Customers (less accumulated provisions of $5,949,000 and $6,153,000 respectively, for uncollectible accounts)............................. 114,009 128,303 Associated companies.................................................... 100,128 45,236 Other................................................................... 17,026 16,184 Prepayments and other..................................................... 12,287 2,551 ---------- ---------- 243,534 202,584 ---------- ---------- DEFERRED CHARGES: Regulatory assets......................................................... 513,664 599,663 Goodwill.................................................................. 898,086 898,086 Accumulated deferred income tax benefits.................................. 98,694 1,517 Other..................................................................... 22,765 21,147 ---------- ---------- 1,533,209 1,520,413 ---------- ---------- $3,114,465 $3,163,254 ========== ========== </TABLE> 137
<TABLE> <CAPTION> PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited) September 30, December 31, 2003 2002 ------------- ------------ (In thousands) CAPITALIZATION AND LIABILITIES ------------------------------ <S> <C> <C> CAPITALIZATION: Common stockholder's equity- Common stock, par value $20 per share, authorized 5,400,000 shares, 5,290,596 shares outstanding.................................. $ 105,812 $ 105,812 Other paid-in capital................................................... 1,215,256 1,215,256 Accumulated other comprehensive loss.................................... (53,881) (69) Retained earnings....................................................... 24,274 32,705 ---------- ---------- Total common stockholder's equity................................... 1,291,461 1,353,704 Company-obligated mandatorily redeemable preferred securities (Note 5).... -- 92,214 Long-term debt and other long-term obligations- Company-obligated mandatorily redeemable preferred securities (Note 5).. 92,374 -- Other................................................................... 343,821 470,274 ---------- ---------- 1,727,656 1,916,192 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt.......................................... 125,860 813 Accounts payable- Associated companies.................................................... 72,537 129,906 Other................................................................... 36,340 29,690 Notes payable to associated companies..................................... 65,720 90,427 Accrued taxes............................................................. 20,537 21,271 Accrued interest.......................................................... 18,259 12,695 Other..................................................................... 21,023 8,409 ---------- ---------- 360,276 293,211 ---------- ---------- DEFERRED CREDITS: Accumulated deferred investment tax credits............................... 10,183 10,924 Nuclear fuel disposal costs............................................... 18,923 18,771 Power purchase contract loss liability.................................... 690,836 765,063 Asset retirement obligation............................................... 103,569 -- Nuclear plant decommissioning costs....................................... -- 135,450 Retirement benefits....................................................... 177,076 -- Other..................................................................... 25,946 23,643 ---------- ---------- 1,026,533 953,851 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 2)........................... ---------- ---------- $3,114,465 $3,163,254 ========== ========== <FN> The preceding Notes to Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these balance sheets. </FN> </TABLE> 138
<TABLE> <CAPTION> PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2003 2002 2003 2002 -------- -------- -------- -------- (In thousands) <S> <C> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 3,975 $ 4,446 $ 17,569 $ 30,140 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........ 10,982 16,098 38,358 45,743 Deferred costs recoverable as regulatory assets.... (4,267) (13,468) (16,146) (41,168) Deferred income taxes, net......................... 6,356 4,525 (31,153) 3,087 Amortization of investment tax credits............. (247) (285) (741) (856) Accrued retirement benefit obligations............. 6,867 -- 18,831 -- Accrued compensation, net.......................... (234) (183) 8,618 (1,206) Cumulative effect of accounting change (Note 5).... -- -- (1,873) -- Receivables........................................ 1,283 9,186 10,075 (466) Accounts payable................................... (93,818) (16,663) (71,846) (15,570) Accrued taxes...................................... (327) (3,144) (735) (22,969) Accrued interest................................... 5,450 6,014 5,564 6,378 Prepayments and other current assets............... (3,923) 14,793 (9,736) 2,096 Other.............................................. (13,005) 1,194 (4,177) 538 -------- -------- -------- -------- Net cash provided from (used for) operating activities ..................................... (80,908) 22,513 (37,392) 5,747 -------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net........................... 38,150 444 -- 26,309 Redemptions and Repayments-............................ Long-term debt....................................... (165) -- (454) (24,973) Short-term borrowings, net........................... -- -- (24,708) -- Dividend Payments- Common stock......................................... (10,000) -- (26,000) (14,000) -------- -------- -------- -------- Net cash provided from (used for) financing activities ..................................... 27,985 444 (51,162) (12,664) -------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions..................................... (10,346) (10,958) (29,123) (33,775) Proceeds from non-utility generation trusts (Note 4)... -- -- 106,327 34,208 Associated companies loans, net........................ 62,597 -- 610 -- Other.................................................. 390 -- 514 (239) -------- -------- -------- -------- Net cash provided from (used for) investing activities ..................................... 52,641 (10,958) 78,328 194 -------- -------- -------- -------- Net increase (decrease) in cash and cash equivalents...... (282) 11,999 (10,226) (6,723) Cash and cash equivalents at beginning of period.......... 366 20,311 10,310 39,033 -------- -------- -------- -------- Cash and cash equivalents at end of period................ $ 84 $ 32,310 $ 84 $ 32,310 ======== ======== ======== ======== <FN> The preceding Notes to Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements. </FN> </TABLE> 139
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 September 30, 2003, and the related consolidated statements of income and cash flows for each of the three-month and nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2002, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report dated February 28, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio November 13, 2003 140
PENNSYLVANIA ELECTRIC COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Penelec provides regulated transmission and distribution services in northern, western and south central Pennsylvania. Pennsylvania customers are able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. Penelec's regulatory plan required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Penelec continues to deliver power to homes and businesses through its existing distribution system and maintains provider of last resort (PLR) obligations to customers who elect to retain Penelec as their power supplier. RESULTS FROM OPERATIONS Net income in the third quarter of 2003 decreased to $4.0 million from $4.4 million in the third quarter of 2002. Lower operating revenues and higher other operating costs were partially offset by reduced purchase power costs as compared to the third quarter of 2002. During the first nine months of 2003, net income decreased to $17.6 million compared to $30.1 million in the first nine months of 2002. Net income in the first nine months of 2003 included an after-tax credit of $1.1 million from the cumulative effect of an accounting change due to the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." Income before the cumulative effect was $16.5 million in the first nine months of 2003 compared with $30.1 million for the corresponding period of 2002. In the first nine months of 2003, higher operating costs and lower operating revenues were partially offset by reduced purchase power costs. Electric Sales Operating revenues decreased by $26.4 million, or 9.8% in the third quarter of 2003 compared with the same period of 2002, primarily due to lower wholesale, residential and commercial kilowatt-hour sales, partially offset by increased industrial kilowatt-hour sales. Wholesale sales revenues decreased by $9.6 million in the third quarter of 2003, which were primarily attributable to lower sales to non-affiliated companies. Retail generation kilowatt-hour sales decreased 5.0% ($9.4 million decrease in revenue) as a result of a 14.5% decrease in residential sales and a 13.2% decrease in commercial sales offset in part by higher industrial sales (31.9%). The significant decrease in residential and commercial sales were primarily due to milder weather in the third quarter of 2003 compared to 2002 and a sluggish, but improving economy. These factors also contributed to the decrease in distribution deliveries of 3.4% in the third quarter of 2003 from the same quarter of 2002, decreasing revenues from electricity throughput by $8.1 million. Operating revenues decreased $20.0 million or 2.7% in the first nine months of 2003 compared to the same period in 2002, reflecting a wholesale sales revenue decrease of $14.8 million, primarily due to lower affiliated company sales. Generation retail kilowatt-hour sales were also lower by 1.6% with a corresponding decrease in revenues of $7.9 million. Lower kilowatt-hour sales to industrial customers were partially offset by higher demand from residential and commercial customers. Changes in electric generation sales and distribution deliveries in the third quarter and the first nine months of 2003 from the corresponding periods of 2002 are summarized in the following table: Changes in Kilowatt-Hour Sales Three Months Nine Months ------------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (5.0)% (1.6)% Wholesale............................. (99.9)% (99.5)% ------------------------------------------------------------------------- Total Electric Generation Sales......... (10.7)% (6.4)% ======================================================================= Distribution Deliveries: Residential........................... (14.6)% 1.5% Commercial............................ (13.1)% 1.0% Industrial............................ 28.1% 2.9% ------------------------------------------------------------------------- Total Distribution Deliveries........... (3.4)% 1.8% ======================================================================= Operating Expenses and Taxes Total operating expenses and taxes decreased $25.9 million or 10.1% in the third quarter of 2003 and decreased $3.6 million or 0.5% in the first nine months of 2003 from the same periods of 2002. The following table presents changes from the prior year by expense category. 141
Operating Expenses and Taxes - Changes Three Months Nine Months Increase (Decrease) (In millions) Purchased power costs............................ $(38.3) $(13.4) Other operating costs............................ 20.4 25.2 - ------------------------------------------------------------------------------- Total operation and maintenance expenses....... (17.9) 11.8 Provision for depreciation and amortization...... (5.1) (7.3) General taxes.................................... (0.7) 1.4 Income taxes..................................... (2.2) (9.5) - ------------------------------------------------------------------------------- Total decrease in operating expenses and taxes. $(25.9) $ (3.6) =============================================================================== Reduced purchased power costs in the third quarter of 2003, compared with the same quarter of 2002, were due to lower required kilowatt-hour purchases driven by lower generation sales. In the first nine months, purchased power costs were lower principally due to fewer kilowatt-hour purchases, partially offset by higher average unit costs. The increase in other operating costs in the third quarter and first nine months of 2003 compared to the same periods of 2002 was primarily due to higher employee benefit costs and costs to restore customer service resulting from significant storm activity. Net Interest Charges Net interest charges decreased by $0.5 million in the third quarter of 2003 and $4.0 million in the first nine months of 2003 compared with 2002, reflecting debt redemptions since the beginning of the third quarter of 2002. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Penelec recorded an after-tax credit to net income of $1.1 million. Penelec identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $93 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $93 million. The asset retirement obligation (ARO) liability at the date of adoption was $99 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, Penelec had recorded decommissioning liabilities of $130 million. Penelec expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, Penelec recognized a regulatory liability of $29 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the liabilities was a $1.9 million increase to income, or $1.1 million net of income taxes. CAPITAL RESOURCES AND LIQUIDITY Penelec's cash requirements in 2003 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without materially increasing its net debt and preferred stock outstanding. Over the next three years, Penelec expects to meet its contractual obligations with cash from operations. Thereafter, Penelec expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of September 30, 2003, Penelec had $0.1 million of cash and cash equivalents, compared with $10.3 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Net cash provided from (used for) operating activities during the third quarter and first nine months of 2003 compared with the corresponding periods of 2002 were as follows: Three Months Ended Nine Months Ended September 30, September 30, Operating Cash Flows 2003 2002 2003 2002 ------------------------------------------------------------------------ (In millions) Cash earnings (1)............ $ 23 $11 $ 34 $ 36 Working capital and other.... (104) 12 (71) (30) ----------------------------------------------------------------------- Total........................ $ (81) $23 $(37) $ 6 ====================================================================== (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. 142
Net cash used for operating activities decreased $104 million in the third quarter of 2003 compared to the same period of 2002, due to a $116 million increase in working capital and other requirements (primarily from changes in accounts payable). Net cash used for operating activities decreased $43 million in the first nine months of 2003 compared to the same period of 2002. This decrease resulted from a $41 million increase in working capital and other requirements primarily attributable to a $56 million change in accounts payable. Cash Flows From Financing Activities In the third quarter of 2003, the increase in net cash provided from financing activities of $28 million as compared to $0.4 million in the same period of 2002 resulted from an increase in net short-term borrowings. As of September 30, 2003, Penelec had about $0.1 million of cash and temporary cash investments and approximately $65.7 million of short-term indebtedness. Penelec may borrow from its affiliates on a short-term basis. Penelec will not issue first mortgage bonds (FMB) other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of September 30, 2003, Penelec had the capability to issue $15 million of additional senior notes based upon FMB collateral. Penelec had no restrictions on the issuance of preferred stock. Cash Flows From Investing Activities Net cash provided from investing activities totaled $53 million in the third quarter of 2003 compared to a use of $11 million in the third quarter of 2002. Net cash provided from investing activities was $78 million in the first nine months of 2003, compared with $0.2 million in the same period of 2002. The net cash in 2003 provided from investing activities resulted from proceeds from loans to associated companies in the third quarter and proceeds from nonutility generation (NUG) trusts in the first nine months, slightly offset by expenditures for property additions in both periods. Refunds to the NUG trusts are expected to be made in 2004 (see Regulatory Matters). Expenditures for property additions primarily support Penelec's energy delivery operations. During the last quarter of 2003, capital requirements for property additions are expected to be about $10 million. Penelec has additional requirements of approximately $0.2 million for maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." Fitch also lowered the senior secured, senior unsecured, and preferred stock ratings of Met-Ed, Penelec, CEI, and TE. In addition, Fitch affirmed the ratings of OE, Penn and JCP&L. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the securities of its electric utility operating companies. Fitch stated that the changes to the long-term ratings were "driven by the high debt leverage of the parent FE. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been vulnerable to unfavorable events, slowing the pace of FE's debt reduction efforts. The Stable Outlook reflects the success of FE's recent common equity offering and management's focus on a relatively conservative integrated utility strategy." On October 27, 2003, Standard & Poors (S&P) stated that the `BBB' corporate credit and the `BBB-` senior unsecured ratings for FirstEnergy and its utility subsidiaries remain on CreditWatch with negative implications. The ratings were placed on CreditWatch on August 18, 2003, and reflect S&P's concerns regarding the potential impact of the August 14, 2003 blackout investigation on FirstEnergy's deleveraging strategy and its overall efforts to improve its credit profile. At that time, S&P also noted other challenges facing FirstEnergy, including the extended Davis-Besse outage; the recent U.S. District Court ruling regarding the Sammis Plant; reliability concerns in subsidiary JCP&L's service territory; and FirstEnergy's credibility with regulators and federal officials. S&P further noted several factors that could aid FirstEnergy in resolution of the CreditWatch, including strengthening its balance sheet. FirstEnergy directly addressed this concern through its recently completed common equity offering that raised approximately $935 million in net proceeds, which was used to reduce bank debt. S&P described the equity offering as a "positive credit development" and also noted the recent renewal of FirstEnergy's 143
$1 billion revolver facilities as a "favorable development, as it mitigates liquidity concerns." S&P also indicated that should various ongoing investigations into the causal factors of the August 14, 2003 blackout establish that the blackout resulted from no negligence or breach of compliance standards on FirstEnergy's part, the CreditWatch could be removed and the outlook returned to negative. S&P deemed a "stable" credit outlook unlikely until issues such as the restart of Davis-Besse are resolved and the potential effect of the litigation relating to the Sammis plant (the second trial is scheduled for April 2004) are known. Extension of the Ohio transition plan will be viewed as a positive development and will support an outlook revision to stable. On October 27, 2003, S&P also noted that the ratings on FirstEnergy and its subsidiaries incorporate such strengths as the ability to generate free cash flow, power generation contracted to its transmission and distribution subsidiaries through 2005, and the hedging of its short power position arising from its PLR obligation in Pennsylvania. S&P said that these strengths are offset by slower than anticipated reduction of FirstEnergy debt, remaining volume risks of PLR obligations, the extended outage at Davis-Besse, the unfavorable outcome of the New Jersey rate proceeding, and regulatory uncertainty in Ohio. S&P also said that it now views FirstEnergy's liquidity position as average, following FirstEnergy's renewal of its $1 billion credit facilities. 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. 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 third quarter and first nine months of 2003 is summarized in the following table: <TABLE> <CAPTION> Increase (Decrease) in the Fair Value Three Months Ended Nine Months Ended of Commodity Derivative Contracts September 30, 2003 September 30, 2003 - --------------------------------------------------------------------------------------------------------------------------- Non-Hedge Hedge Total Non-Hedge Hedge Total --------- ----- ----- --------- ----- ----- (In millions) Change in the Fair Value of Commodity Derivative Contracts <S> <C> <C> <C> <C> <C> <C> Net asset at beginning of period....................... $12.9 $ -- $12.9 $ 8.7 $ 0.1 $ 8.8 New contract value when entered........................ -- -- -- -- -- -- Additions/Increase in value of existing contracts...... (0.1) -- (0.1) 4.1 -- 4.1 Change in techniques/assumptions....................... 2.3 -- 2.3 2.3 -- 2.3 Settled contracts...................................... -- -- -- -- (0.1) (0.1) - -------------------------------------------------------- ------------------------- ----------------------------- Net Assets - Derivative Contracts at end of period (1). $15.1 $ -- $15.1 $15.1 $ -- $15.1 ======================================================== ========================= ============================= Impact of Changes in Commodity Derivative Contracts (2) Income Statement Effects (Pre-Tax)..................... $ 0.2 $ -- $ 0.2 $ 0.4 $ -- $ 0.4 Balance Sheet Effects: Other Comprehensive Income (Pre-Tax)................ $ -- $ -- $ -- $ -- $(0.1) $(0.1) Regulatory Liability................................ $ 2.0 $ -- $ 2.0 $ 6.0 $ -- $ 6.0 (1) Includes $14.2 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. </TABLE> Derivatives included on the Consolidated Balance Sheet as of September 30, 2003: Non-Hedge Hedge Total --------- ----- ----- (In millions) Current- Other Assets............................ $ -- $ -- $ -- Other Liabilities....................... -- -- -- Non-Current- Other Deferred Charges.................. 15.1 -- 15.1 Other Deferred Credits.................. -- -- -- ---------------------------------------------------------------------------- Net Assets.............................. $15.1 $ -- $15.1 ============================================================================ 144
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: <TABLE> <CAPTION> Source of Information - - Fair Value by Contract Year 2003(1) 2004 2005 2006 Thereafter Total - --------------------------------------------------------------------------------------------------------- (In millions) <S> <C> <C> <C> <C> <C> <C> Prices based on external sources(2) $0.3 $2.1 $2.3 $-- $-- $ 4.7 Prices based on models -- -- -- 2.4 8.0 10.4 - --------------------------------------------------------------------------------------------------------- Total3 $0.3 $2.1 $2.3 $2.4 $8.0 $15.1 ========================================================================================================= (1) For the last quarter of 2003. (2) Broker quote sheets. (3) Includes $14.2 million from an embedded option that is offset by a regulatory liability and does not affect earnings. </TABLE> Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of September 30, 2003. Equity Price Risk Included in Penelec's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $48 million and $42 million as of September 30, 2003 and December 31, 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of September 30, 2003. OUTLOOK Beginning in 1999, all of Penelec's customers were able to select alternative energy suppliers. Penelec continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. The Pennsylvania Public Utility Commission (PPUC) authorized Penelec's rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a competitive transition charge (CTC). Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. Penelec has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as its PLR obligation. Regulatory assets are costs which have been authorized by the PPUC and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of Penelec's regulatory assets are expected to continue to be recovered under the provisions of the regulatory plan as discussed below. Penelec's regulatory assets totaled $514 million and $600 million as of September 30, 2003 and December 31, 2002, respectively. Regulatory Matters Effective September 1, 2002, Penelec assigned its provider of last resort (PLR) responsibility to its unregulated supply affiliate, FirstEnergy Solutions Corp. (FES), through a wholesale power sale agreement which expires in December 2003 and may be extended for each successive calendar year. Under the terms of the wholesale agreement, FES assumed the supply obligation, and the energy supply profit and loss risk, for the portion of power supply requirements that Penelec does not self-supply under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces its 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 to FES. Penelec is authorized to continue deferring differences between NUG contract costs and current market prices. 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 Administrative Law Judge 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. 145
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 order on two issues: to establish the end of June 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 findings would not impair Penelec's 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 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 refunds; and, 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. Met-Ed and Penelec are considering filing an appeal to the Commonwealth Court on the PPUC orders as well. Environmental Matters Penelec has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2003, based on estimates of the total costs of cleanup, Penelec's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Penelec has total accrued liabilities aggregating approximately $0.2 million as of September 30, 2003. Penelec does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. Legal Matters Various lawsuits, claims and proceedings related to Penelec's normal business operations are pending against it, the most significant of which are described above. SIGNIFICANT ACCOUNTING POLICIES Penelec prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect its financial results. All of its assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. Penelec's more significant accounting policies are described below. Purchase Accounting The merger between FirstEnergy and GPU was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities were based primarily on estimates. The adjustments reflected in Penelec's records, which were finalized in the fourth quarter of 2002, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," Penelec evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. 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 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 of goodwill indicated. The forecasts used in its evaluation of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on Penelec's future evaluation of goodwill. As of September 30, 2003, Penelec had recorded goodwill of approximately $898.1 million related to the merger. 146
Regulatory Accounting Penelec is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine it is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Pennsylvania, a significant amount of regulatory assets have been recorded - $514 million as of September 30, 2003. Penelec regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. Penelec continually monitors its derivative contracts to determine if Penelec's activities, expectations, intentions, assumptions and estimates remain valid. As part of Penelec's normal operations, it enters into commodity contracts which increase the impact of derivative accounting judgments. Revenue Recognition Penelec follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet been billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and OPEB are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 147
2002 and 2001, plan assets have earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy is not required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to FirstEnergy's 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," Penelec periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, Penelec would recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). RECENTLY ISSUED ACCOUNTING STANDARDS FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". This Interpretation requires the consolidation of a variable interest entity (VIE) by an enterprise if that enterprise either absorbs a majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns as a result of ownership, contractual or other financial interests in the VIE. Currently, entities are generally consolidated by an enterprise that has a controlling financial interest through ownership of a majority voting interest in the entity. FIN 46 defines a VIE as an entity in which equity investors do not have the characteristics of a controlling financial interest nor have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. VIE's created after January 31, 2003, are immediately subject to the provisions of FIN 46. The FASB recently deferred implementation of FIN 46 for VIE's created before February 1, 2003, until the first reporting period ending after December 15, 2003 (Penelec's quarter ending December 31, 2003.) As described in Note 1, the consolidated financial statements of Penelec include a statutory business trust that sold trust-preferred securities in which Penelec is not the primary beneficiary. Pending further guidance from the FASB that would indicate otherwise, this entity may not be consolidated in Penelec's financial statements as of December 31, 2003. The deconsolidation would result in an increase in total assets and liabilities of approximately $3.1 million for the investment in the trust. The FASB continues to provide additional guidance on implementing FIN 46 and recently proposed modifications and clarifications with a comment period ending December 1, 2003. As this guidance is finalized, Penelec will continue to assess the accounting and disclosure impact of FIN 46 with respect to potential VIE's. SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Issued by the FASB in April 2003, SFAS 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS 133 for decisions made by the Derivative Implementation Group (DIG), as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for reporting periods which began prior to June 15, 2003, that continue to be applied based on their original effect dates. Adoption of SFAS 149 did not have a material impact on Penelec's financial statements. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, 148
certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the beginning of the first interim period beginning after June 15, 2003 (Penelec's third quarter of 2003) for all other financial instruments. Upon adoption of SFAS 150, effective July 1, 2003, company-obligated mandatorily redeemable preferred securities of $92.4 million were reclassified and included in long-term debt as of September 30, 2003. As required by SFAS 150, the preferred securities subject to mandatory redemption were not restated as long-term debt on the December 31, 2002 balance sheet. DIG Implementation Issue No. C20 for SFAS 133, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature" In June 2003, the FASB cleared DIG Issue C20 for implementation in fiscal quarters beginning after July 10, 2003 which would correspond to Penelec's fourth quarter of 2003. The issue supersedes earlier DIG Issue C11, "Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception." DIG Issue C20 provides guidance regarding when the presence of a general index, such as the Consumer Price Index, in a contract would prevent that contract from qualifying for the normal purchases and normal sales (NPNS) exception under SFAS 133, as amended, and therefore exempt from the mark-to-market treatment of certain contracts. DIG Issue C20 is to be applied prospectively to all existing contracts as of its effective date and for all future transactions. If it is determined under DIG Issue C20 guidance that the NPNS exception was claimed for an existing contract that was not eligible for this exception, the contract will be recorded at fair value, with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle in the fourth quarter of 2003. Penelec is currently assessing the new guidance but does not anticipate any material impact on its financial statements. EITF Issue No. 01-08, "Determining whether an Arrangement Contains a Lease" In May 2003, the EITF reached a consensus on Issue No. 01-08, regarding when arrangements contain a lease. Based on the EITF consensus, an arrangement contains a lease if (1) it identifies specific property, plant or equipment (explicitly or implicitly), and (2) the arrangement transfers the right to the purchaser to control the use of the property, plant or equipment. The consensus is to be applied prospectively to arrangements committed to, modified or acquired through a business combination, beginning in the third quarter of 2003. The adoption of this consensus as of July 1, 2003 did not impact Penelec's financial statements. 149
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 September 30, 2003, 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. 150
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 auditors 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. JCP&L ----- 12 Fixed charge ratios 15 Letter from independent auditors 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, OE and Penn ------------------------ 15 Letter from independent public auditors 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. Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of their respective total assets of FirstEnergy and its subsidiaries on a consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec but hereby agree to furnish to the Commission on request any such documents. (b) Reports on Form 8-K FirstEnergy- ----------- FirstEnergy filed thirteen reports on Form 8-K since June 30, 2003. A report dated July 24, 2003 reported an updated Davis-Besse ready for restart schedule and cost estimates. A report dated July 25, 2003 reported the New Jersey Board of Public Utilities decision on JCP&L's rate proceedings. A report dated August 5, 2003 reported FirstEnergy's second quarter 2003 earnings results and other information. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements and restatement and reaudit of 2001 CEI and TE financial statements. A report dated August 7, 2003 reported the pending restatement and reaudit of 2000 CEI and TE financial statements. A report dated August 8, 2003 reported a U.S. District Court ruling 151
with respect to the W. H. Sammis Plant under the Clean Air Act. A report dated August 28, 2003 reported FirstEnergy's cash and liquidity position. A report dated September 8, 2003 reported the announcement of a public offering of additional common stock and a Regulation G reconciliation of a non-GAAP financial measure, free cash flow, presented in connection with the offering. A report dated September 12, 2003 reported that FirstEnergy, OE, CEI and TE had received an informal data request from the Securities and Exchange Commission to provide information related to their recent financial statement restatements. A report dated September 24, 2003 reported an underwriting agreement related to its public offering of additional common stock. A report dated October 21, 2003 reported the filing of a proposed rate stabilization plan with the PUCO. A report dated October 23, 2003, reported FirstEnergy's third quarter 2003 results and other information. A report dated November 13, 2003 reported the announcement of a settlement agreement of FirstEnergy's claim against NRG Energy for the cancellation of a generating plants sale. OE -- OE filed four reports on Form 8-K since June 30, 2003. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements. A report dated August 8, 2003 reported a U.S. District Court ruling with respect to the W. H. Sammis Plant under the Clean Air Act. A report dated September 12, 2003 reported that FirstEnergy, OE, CEI and TE had received an informal data request from the Securities and Exchange Commission to provide information related to their recent financial statement restatements. A report dated October 21, 2003 reported the filing of a proposed rate stabilization plan with the PUCO. Penn ---- None CEI --- CEI filed six reports on Form 8-K since June 30, 2003. A report dated July 24, 2003 reported an updated Davis-Besse ready for restart schedule and cost estimates. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements and restatement and reaudit of 2001 CEI and TE financial statements. A report dated August 7, 2003 reported the pending restatement and reaudit of 2000 CEI and TE financial statements. A report dated September 12, 2003 reported that FirstEnergy, OE, CEI and TE had received an informal data request from the Securities and Exchange Commission to provide information related to their recent financial statement restatements. A report dated October 21, 2003 reported the filing of a proposed rate stabilization plan with the PUCO. A report dated November 13, 2003 reported the announcement of a settlement agreement of FirstEnergy's claim against NRG Energy for the cancellation of a generating plants sale. TE -- TE filed six reports on Form 8-K since June 30, 2003. A report dated July 24, 2003 reported an updated Davis-Besse ready for restart schedule and cost estimates. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements and restatement and reaudit of 2001 CEI and TE financial statements. A report dated August 7, 2003 reported the pending restatement and reaudit of 2000 CEI and TE financial statements. A report dated September 12, 2003 reported that FirstEnergy, OE, CEI and TE had received an informal data request from the Securities and Exchange Commission to provide information related to their recent financial statement restatements. A report dated October 21, 2003 reported the filing of a proposed rate stabilization plan with the PUCO. A report dated November 13, 2003 reported the announcement of a settlement agreement of FirstEnergy's claim against NRG Energy for the cancellation of a generating plants sale. Met-Ed and Penelec ------------------ None JCP&L ----- JCP&L filed one report on Form 8-K since June 30, 2003. A report dated July 25, 2003 reported the New Jersey Board of Public Utilities decision on JCP&L's rate proceedings. 152
SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. November 14, 2003 FIRSTENERGY CORP. ----------------- Registrant OHIO EDISON COMPANY ------------------- Registrant THE CLEVELAND ELECTRIC ---------------------- ILLUMINATING COMPANY -------------------- Registrant THE TOLEDO EDISON COMPANY ------------------------- Registrant PENNSYLVANIA POWER COMPANY -------------------------- Registrant JERSEY CENTRAL POWER & LIGHT COMPANY ------------------------------------ Registrant METROPOLITAN EDISON COMPANY --------------------------- Registrant PENNSYLVANIA ELECTRIC COMPANY ----------------------------- Registrant /s/ Harvey L. Wagner --------------------------------------- Harvey L. Wagner Vice President, Controller and Chief Accounting Officer 153