UNITED STATES SECURITIES AND EXCHANGE COMMISSION
FORM 10-Q
(Mark One)
For the quarterly period ended September 30, 2004
OR
For the transition period from to
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):
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company common stock. Ohio Edison Company is the sole holder of Pennsylvania Power Company common stock.
This combined Form 10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy Corp.
This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms “anticipate”, “potential”, “expect”, “believe”, “estimate” and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), adverse regulatory or legal decisions and the outcome of governmental investigations (including revocation of necessary licenses or operating permits), availability and cost of capital, the continuing availability and operation of generating units, the inability to accomplish or realize anticipated benefits of strategic goals, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities markets, further investigation into the causes of the August 14, 2003 regional power outages and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to those outages, the final outcome in the proceeding related to FirstEnergy’s Application for a Rate Stabilization Plan in Ohio, the risks and other factors discussed from time to time in the registrants’ Securities and Exchange Commission filings, including their annual report on Form 10-K (as amended) for the year ended December 31, 2003 and other similar factors. The registrants expressly disclaim any current intention to update any forward-looking statements contained in this document as a result of new information, future events, or otherwise.
TABLE OF CONTENTS
TABLE OF CONTENTS (Cont’d)
GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
The following abbreviations and acronyms are used to identify frequently used terms in this report:
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GLOSSARY OF TERMS, Cont.
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PART I. FINANCIAL INFORMATION
FIRSTENERGY CORP. AND SUBSIDIARIESOHIO EDISON COMPANY AND SUBSIDIARIESTHE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIESTHE TOLEDO EDISON COMPANY AND SUBSIDIARYPENNSYLVANIA POWER COMPANY AND SUBSIDIARYJERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIESMETROPOLITAN EDISON COMPANY AND SUBSIDIARIESPENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES
1 - ORGANIZATION AND BASIS OF PRESENTATION:
The principal business of FirstEnergy is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE. JCP&L, Met-Ed and Penelec were acquired in a merger (which was effective November 7, 2001) with GPU, the former parent company of JCP&L, Met-Ed and Penelec. The merger was accounted for by the purchase method of accounting and the applicable effects were reflected on the financial statements of JCP&L, Met-Ed and Penelec as of the merger date. FirstEnergy’s consolidated financial statements also include its other principal subsidiaries: FENOC, FES and its subsidiary FGCO, FESC, FirstCom, FSG, GPU Capital, GPU Power and MYR.
FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, FERC and, as applicable, PUCO, PPUC and NJBPU. The consolidated unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform with the current year presentation. In particular, expenses (including transmission and congestion charges) were reclassified among purchased power, other operating costs and depreciation and amortization to conform with the current year presentation of generation commodity costs. As discussed in Note 8, segment reporting in 2003 was reclassified to conform with the current year business segment organizations and operations. In addition, revenues, expenses and taxes related to certain divestitures in 2003 have been reclassified and reported net as discontinued operations (see Note 2) and certain revenues and expenses have been reclassified and presented on a net basis to conform with the current year presentation.
These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2003 for FirstEnergy and the Companies. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from those estimates. The reported results of operations are not indicative of results of operations for any future period.
FirstEnergy’s and the Companies’ independent registered public accounting firm has performed reviews of, and issued reports on, these consolidated interim financial statements in accordance with standards established by the PCAOB. 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 registered public accounting firm’s liability under Section 11 does not extend to them.
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Consolidation
FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest, and VIEs for which FirstEnergy or any of its subsidiaries is the primary beneficiary. Intercompany transactions and balances are eliminated in consolidation. Investments in nonconsolidated affiliates (20-50 percent owned companies, joint ventures and partnerships) over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control, are accounted for on the equity basis.
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FIN 46R addresses the consolidation of VIEs, including SPEs, that are not controlled through voting interests or in which the equity investors do not bear the residual economic risks and rewards. The first step under FIN 46R is to determine whether an entity is within the scope of FIN 46R, which occurs if it is deemed to be a VIE. FirstEnergy and its subsidiaries consolidate VIEs where they have determined that they are the primary beneficiaries as defined by FIN 46R.
Included in FirstEnergy’s consolidated financial statements are PNBV and Shippingport, two VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.
PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent equity interest by a nonaffiliated third party and a three-percent equity interest held by OES Ventures, a wholly owned subsidiary of OE. As required by FIN 46R, consolidation of PNBV by FirstEnergy and OE as of December 31, 2003 changed the previously reported trust investment of $361 million to an investment in collateralized lease bonds of $372 million. The $11 million increase represented the minority interest in the total assets of PNBV.
Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport. Consolidation of this entity by CEI impacted the financial statements of CEI and TE but had no impact on the consolidated financial statements of FirstEnergy. Prior to the adoption of FIN 46R, the assets and liabilities of Shippingport were included on a proportionate basis in the financial statements of CEI and TE. Adoption of FIN 46R resulted in the consolidation of Shippingport by CEI as of December 31, 2003. Shippingport’s note payable to TE of $199 million ($10 million current) and $208 million ($9 million current) as of September 30, 2004 and December 31, 2003, respectively, is included in long-term debt on CEI’s Consolidated Balance Sheets.
Through its investment in PNBV, OE has, and through their investments in Shippingport, CEI and TE have, variable interests in certain owner trusts that acquired the interests in the Perry Plant and Beaver Valley Unit 2, in the case of OE, and the Bruce Mansfield Plant, in the case of CEI and TE. FirstEnergy concluded that OE, CEI and TE were not the primary beneficiaries of the relevant owner trusts and were therefore not required to consolidate these entities. The leases are accounted for as operating leases in accordance with GAAP. The combined purchase price of $3.1 billion for all of the interests acquired by the owner trusts in 1987 was funded with debt of $2.5 billion and equity of $600 million.
Each of OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $696 million, $113 million and $572 million, respectively, that would not be payable if the casualty value payments are made. As of September 30, 2004, CEI and TE have recorded above-market lease obligations related to the Bruce Mansfield Plant and Beaver Valley Unit 2 totaling $1.0 billion (CEI–$744 million and TE–$299 million), of which $85 million (CEI–$60 million and TE–$25 million) is current.
CEI formed a wholly owned statutory business trust to sell preferred securities and invest the gross proceeds in 9% subordinated debentures of CEI. The sole assets of the trust are the subordinated debentures with an aggregate principal amount of $103 million. The trust’s preferred securities are redeemable at 100% of their principal amount at CEI’s option beginning in December 2006. CEI has effectively provided a full and unconditional guarantee of the trust’s obligations under the preferred securities.
Met-Ed and Penelec each formed statutory business trusts for substantially similar transactions to those of CEI. However, ownership of the Met-Ed and Penelec trusts is through separate wholly owned limited partnerships. On June 1, 2004, Met-Ed extinguished the subordinated debentures held by its affiliated trust and redeemed all of the associated 7.35% preferred securities (aggregate value of $100 million). On September 1, 2004, Penelec extinguished the subordinated debentures held by its affiliated trust and redeemed all of the associated 7.34% preferred securities (aggregate value of $100 million).
Upon adoption of FIN 46R, the limited partnerships and statutory business trusts discussed above were no longer consolidated on the financial statements of FirstEnergy or, as applicable, CEI, Met-Ed or Penelec. As of December 31, 2003 and September 30, 2004, subordinated debentures held by the affiliated trusts were included in long-term debt of the applicable company and equity investments in the trusts were included in other investments.
FirstEnergy has evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and
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Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were structured pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.
FirstEnergy has determined that for all but nine of these entities, neither JCP&L, Met-Ed or Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining nine entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants.
As required by FIN 46R, FirstEnergy has requested each quarter the information necessary from these nine entities to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases, was deemed by the requested entity to be competitive and proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. The purchased power costs from these entities during the three months and nine months ended September 30, 2004 and 2003 were as follows:
FirstEnergy is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information.
Earnings Per Share
Basic earnings per share are computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. Stock-based awards to purchase shares of common stock totaling 3.4 million in the nine months ended September 30, 2004 and 3.5 million in the three months and nine months ended September 30, 2003 were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. No stock-based awards were excluded from the calculation for the quarter ended September 30, 2004. The following table reconciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations and Cumulative Effect of Accounting Change:
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Preferred Stock Subject to Mandatory Redemption
Long-term debt includes the preferred stock of consolidated subsidiaries subject to mandatory redemption as of September 30, 2004 and December 31, 2003 in accordance with SFAS 150. Issued in May 2003 and effective July 1, 2003, SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity; certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. The adoption of SFAS 150 had no impact on FirstEnergy’s Consolidated Statements of Income because dividends on applicable subsidiary preferred stock were previously included in net interest charges and required no reclassification. CEI and Penn, however, did not include the preferred dividends on their manditorily redeemable preferred stock in interest expense for the first six months of 2003, but have included the dividends in interest charges for the three months ended September 30, 2004 and 2003, and the nine months ended September 30, 2004.
Securitized Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition, a wholly owned limited liability company of JCP&L. In June 2002, JCP&L Transition sold $320 million of transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station.
JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are obligations of JCP&L Transition only and are collateralized solely by the equity and assets of JCP&L Transition, which consist primarily of bondable transition property. The bondable transition property is solely the property of JCP&L Transition.
Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L sold the bondable transition property to JCP&L Transition and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreement with JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of $100,000 that is payable from TBC collections.
Derivative Accounting
FirstEnergy is exposed to financial risks resulting from 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.
Derivatives are recognized as assets or liabilities at fair value unless they qualify for an exception under SFAS 133. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met. Gains and losses from derivative contracts that do not qualify as hedges of commodity price or interest rate risk are included in other operating expenses.
SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The ineffective portion of hedge gains and losses is also included in net income. 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. In 2001, FirstEnergy entered into interest rate derivative transactions to hedge a portion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from these cash flow hedges were reported in other comprehensive income and are included in net income over the periods that the hedged interest payments are made – 5, 10 and 30 years.
The net deferred loss of $93 million included in AOCL as of September 30, 2004, for derivative hedging activity, as compared to the June 30, 2004 balance of $100 million in net deferred losses, resulted from a $5 million reduction related to current hedging activity and a $2 million decrease due to net hedge losses included in earnings during the three months ended September 30, 2004. Approximately $12 million (after tax) of the net deferred loss on derivative instruments in AOCL as of September 30, 2004, is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will fluctuate from period to period based on various market factors.
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FirstEnergy has entered into fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. As of September 30, 2004, FirstEnergy maintained fixed-for-floating interest rate swap agreements with an aggregate notional amount of $1.7 billion. Under these agreements, FirstEnergy receives fixed cash flows based on the fixed coupons of hedged securities and pays variable cash flows based on short-term variable market interest rates. The weighted average fixed interest rate of senior notes and subordinated debentures hedged by the swap agreements was 5.53%. The interest rate swaps have effectively converted that rate to a current, weighted average variable interest rate of 3.02%. Changes in the fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset, liability, or unrecognized firm commitment are recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings. FirstEnergy did not enter into any new fixed-for-floating interest rate swap agreements during the third quarter of 2004.
Goodwill
In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is indicated, FirstEnergy recognizes a loss – calculated as the difference between the implied fair value of a reporting unit’s goodwill and the carrying value of the goodwill. FirstEnergy’s 2003 annual review resulted in a non-cash goodwill impairment charge of $122 million in the third quarter of 2003, reducing the carrying value of FSG. Of this amount, $117 million was reported as an operating expense and $5 million was included in the results from discontinued operations. The impairment charge reflected the slow down in the development of competitive retail markets and depressed economic conditions that affected the value of FSG. The fair value of FSG was estimated using primarily the expected discounted future cash flows. FirstEnergy’s 2004 annual review was completed in the third quarter of 2004 with no impairment indicated.
As of September 30, 2004, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. In the first nine months of 2004, FirstEnergy adjusted goodwill related to the former GPU companies for interest received on a pre-merger income tax refund and for the reversal of tax valuation allowances related to income tax benefits realized attributable to prior period capital loss carryforwards that were offset by capital gains generated in 2004. A summary of the change in goodwill during the nine months ended September 30, 2004 is shown below:
Asset Retirement Obligations
FirstEnergy recognizes a liability for retirement obligations associated with tangible assets in accordance with SFAS 143. FirstEnergy has identified applicable legal obligations as defined under the standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant and closure of two coal ash disposal sites. The ARO liability was $1.060 billion as of September 30, 2004 and included $1.046 billion for nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The Companies’ share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy utilized an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO.
In the third quarter of 2004, FirstEnergy revised the ARO associated with TMI-2 as the result of a recently completed study and the anticipated operating license extension at TMI-1. The abandoned TMI-2 is adjacent to TMI-1 and the units will be decommissioned on a concurrent timeline. The license holder at TMI-1 has indicated plans to file for a 20-year extension of its operating license, which currently expires in 2014. The decrease in the present value of estimated cash flows associated with the license extension of $202 million, was partially offset by the $26 million present value of an increase in projected decommissioning costs. The net decrease in the TMI-2 ARO liability and corresponding regulatory asset was $176 million (JCP&L — $43 million, Met-Ed - $89 million and Penelec — $44 million).
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The Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of September 30, 2004, the fair value of the decommissioning trust assets was $1.462 billion.
The following tables provide the beginning and ending aggregate carrying amount of the ARO and the changes to the balance during the three months and nine months ended September 30, 2004 and 2003, respectively.
Stock-Based Compensation
FirstEnergy applies the recognition and measurement principles of APB 25 and related Interpretations in accounting for its stock-based compensation plans. No material stock-based employee compensation expense is reflected in net income as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value.
In March 2004, the FASB issued an exposure draft of a proposed standard that, if adopted, will change the accounting for employee stock options and other equity-based compensation. The proposed standard would require companies to expense the fair value of stock options determined on the grant date. In October 2004, the FASB amended the proposed standard to delay its effective date from January 1, 2005 to interim and annual periods beginning after June 15, 2005 (see Note 7). FirstEnergy will not be able to determine the impact of the proposed standard until it is issued in final form. The table below summarizes the effects on the Company’s net income and earnings per share had the Company applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation in the current reporting periods.
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Discontinued Operations
FirstEnergy’s discontinued operations consisted of net income of $1 million in the third quarter of 2003 and net losses of $65 million in the first nine months of 2003 from its Argentina and Bolivia businesses and certain domestic operations divested in 2003. The related revenues, expenses and taxes were reclassified from the previously reported Consolidated Statement of Income for the nine months ended September 30, 2003 and reported as a net amount in Discontinued Operations. In April 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa’s parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy’s shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. As a result of the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67 million (no income tax benefit was recognized), or $0.23 per share of common stock, in the second quarter of 2003. This charge resulted from realizing CTA losses through earnings ($90 million, or $0.30 per share of common stock), partially offset by the gain recognized from abandoning FirstEnergy’s investment in Emdersa ($23 million, or $0.07 per share of common stock). Since FirstEnergy had previously recorded $90 million of CTA adjustments in OCI, the net effect of the $67 million charge was an increase in common stockholders’ equity of $23 million. FirstEnergy sold its Bolivia operations, Empresa Guaracachi S.A., in December 2003. Domestic operations sold in 2003 consisted of three former FSG subsidiaries and the MARBEL subsidiary, NEO.
Cumulative Effect of Accounting Change
As a result of adopting SFAS 143 in January 2003, FirstEnergy recorded a $175 million increase to income, $102 million net of tax, or basic earnings of $0.35 per share ($0.34 diluted) of common stock in the nine months ended September 30, 2003. Upon adoption of the accounting standard, FirstEnergy reversed accrued nuclear plant decommissioning costs of $1.23 billion and recorded an ARO of $1.11 billion, including accumulated accretion of $507 million for the period from the date the liability was incurred to the date of adoption. FirstEnergy also recorded asset retirement costs of $602 million as part of the carrying amount of the related long-lived asset and accumulated depreciation of $415 million. FirstEnergy recognized a regulatory liability of $185 million for the transition amounts expected to be recovered through rates related to the ARO for nuclear decommissioning. The cumulative effect adjustment also included the reversal of $60 million in accumulated estimated removal costs for non-regulated generation assets.
The impact of adopting SFAS 143 on the financial statements of each of the Companies effective January 1, 2003, is shown in the table below:
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Restatements of TE, JCP&L and Penelec Previously Reported Quarterly Results
Earnings for the three months and nine months ended September 30, 2003 have been restated for TE, JCP&L and Penelec to reflect adjustments to costs that were subsequently capitalized to construction projects. The results for TE have also been restated to correct the amount reported for interest expense. TE’s costs, which were originally recorded as operating expenses and subsequently capitalized to construction, were $1.1 million ($0.7 million after-tax) and $2.1 million ($1.2 million after-tax) in the third quarter and the first nine months of 2003, respectively. TE’s interest expense was overstated by $0.3 million ($0.2 million after-tax) and $1.6 million ($1.0 million after-tax) in the third quarter and the first nine months of 2003, respectively. Similar to TE, JCP&L’s capital costs originally recorded as operating expenses were $5.8 million ($3.4 million after-tax) and $9.0 million ($5.3 million after-tax) in the third quarter and the first nine months of 2003, respectively. Penelec’s capital costs originally recorded as operating expenses were $2.0 million ($1.2 million after-tax) and $2.7 million ($1.6 million after-tax) in the third quarter and the first nine months of 2003, respectively. In addition, certain revenues and expenses have been reclassified and presented on a net basis to conform with the current year presentation (see Note 1). The impacts of these adjustments were not material to the consolidated balance sheets or consolidated statements of cash flows for TE, JCP&L or Penelec for any quarter of 2003.
The effects of these adjustments on the consolidated statements of income previously reported for TE, JCP&L and Penelec for the three months and nine months ended September 30, 2003 are as follows:
TE
JCP&L
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Penelec
3 — COMMITMENTS, GUARANTEES AND CONTINGENCIES:
Capital Expenditures
FirstEnergy’s current forecast reflects expenditures of approximately $2.3 billion (OE–$295 million, CEI–$275 million, TE–$141 million, Penn–$143 million, JCP&L–$446 million, Met-Ed–$168 million, Penelec–$198 million, ATSI–$66 million, FES–$443 million and other subsidiaries–$125 million) for property additions and improvements from 2004-2006, of which approximately $717 million (OE–$113 million, CEI–$92 million, TE–$48 million, Penn–$65 million, JCP&L–$142 million, Met-Ed–$53 million, Penelec–$60 million, ATSI–$24 million, FES–$87 million and other subsidiaries-$33 million) is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $303 million (OE–$84 million, CEI–$100 million, TE–$64 million and Penn–$55 million), of which approximately $90 million (OE–$26 million, CEI–$30 million, TE–$16 million and Penn–$18 million) applies to 2004.
Guarantees and Other Assurances
As part of normal business activities, FirstEnergy and the Companies enter into various agreements to provide financial or performance assurances to third parties. As of September 30, 2004, outstanding guarantees and other assurances aggregated $2.1 billion and included contract guarantees ($1.0 billion), surety bonds ($0.3 billion) and letters of credit ($0.8 billion).
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 is remote that such parental guarantees of $0.9 billion (included in the $1.0 billion discussed above) as of September 30, 2004 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.
While guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate payment of cash collateral or provision of an LOC may be required. The following table summarizes collateral provisions as of September 30, 2004:
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Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $280 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.
In connection with the sale of the TEBSA project in Colombia in January 2004, FirstEnergy guaranteed the obligations of the operators of the project, up to a maximum of $6 million (subject to escalation) under the project’s operation and maintenance agreement for so long as such obligations exist. The purchaser of TEBSA agreed to indemnify FirstEnergy against any loss under this guarantee. Also in connection with the TEBSA project, FirstEnergy has provided the TEBSA project lenders with a $60 million LOC and a $400,000 LOC. The $60 million LOC was established as a substitute asset for FirstEnergy’s interest in its Midlands companies pursuant to an indemnity agreement in favor of the TEBSA project lenders. As of October 15, 2004, the value of the LOC decreased to $46 million. The balance will continue to decline annually and will be fully discharged and released in October 2010. The substitute LOC enabled FirstEnergy to sell its remaining 20.1% interest in Avon (parent of Midlands Electricity in the United Kingdom). The $400,000 LOC was established to secure the TEBSA project lenders in the event that liquidated shares of TEBSA were unable to be converted into U.S. currency. The $400,000 LOC will terminate upon the registration of certain of TEBSA’s stock with the Colombian Central Bank.
Environmental Matters
Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy’s earnings and competitive position. These environmental regulations affect FirstEnergy’s earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $91 million for 2004 through 2006, which is included in the $2.3 billion of forecasted capital expenditures for 2004 through 2006.
Clean Air Act Compliance
The Companies are required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2regulations 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 complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies’ facilities. The EPA’s NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOxemissions are contributing significantly to ozone levels in the eastern United States. SIPs were required to comply by May 31, 2004 with individual state NOxbudgets. New Jersey and Pennsylvania submitted a SIP that required compliance with the state NOx budgets at the Companies’ New Jersey and Pennsylvania facilities by May 1, 2003. Michigan and Ohio submitted a SIP that required compliance with the state NOx budgets at the Companies’ Michigan and Ohio facilities by May 31, 2004. The Companies believe their facilities are complying with the state NOx budgets through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.
National Ambient Air Quality Standards
In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed the “Interstate Air Quality Rule” covering a total of 29 states (including New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the “8-hour” ozone NAAQS in other states. The EPA has proposed the Interstate Air Quality Rule to “cap-and-trade” NOx and SO2emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO2 emissions would be reduced by approximately 3.6 million tons in 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations
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may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a “co-benefit” from implementation of SO2 and NOx emission caps under the EPA’s proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year. The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.
W. H. Sammis Plant
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of “best available control technology” and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase trial to address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant has been rescheduled to January 2005 by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, that the remedies it “may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act.” The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy’s, OE’s and Penn’s respective financial condition and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of September 30, 2004.
Regulation of Hazardous Waste
As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.
The Companies have been named as PRPs at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are 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, 2004, 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 SBC. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $65 million (JCP&L–$45.8 million, CEI–$2.4 million, TE–$0.2 million, Met-Ed–$28,000, Penelec–$26,000, and other–$16.3 million) as of September 30, 2004. The Companies accrue environmental liabilities only when they can conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in the Companies’ determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
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Climate Change
In December 1997, delegates to the United Nations’ climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the U.S. Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity – the ratio of emissions to economic output – by 18% through 2012.
The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2 emissions could require significant capital and other expenditures. However, the CO2 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies’ diversified generation sources which includes low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to the Companies’ plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies’ operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are drawn into a facility’s cooling water system. The Companies are conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance standards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may be substantial.
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic states experienced a severe heat wave which resulted in power outages throughout the service territories of many electric utilities, including JCP&L’s territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, and strict products liability. In November 2003, the trial court granted JCP&L’s motion to decertify the class and denied plaintiffs’ motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Court issued a decision on July 8, 2004, affirming the decertification of the originally certified class but remanding for certification of a class limited to those customers directly impacted by the outages of transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Court. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of September 30, 2004.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy’s service area. On April 5, 2004, the U.S. –Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid’s reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility’s system. The final report contains 46
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“recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 (see Regulatory Matters below). FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of September 30, 2004 for any expenditures in excess of those actually incurred through that date.
Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. In addition to the one case that was refiled at the PUCO, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.
One complaint has been filed against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on October 22, 2004. No damage estimate has been provided and thus potential liability has not been determined.
FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be instituted against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition and results of operations.
Nuclear Plant Matters
FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse plant. FirstEnergy is unable to predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002. Further, a petition was filed with the NRC on March 29, 2004 by a group objecting to the NRC’s restart order of the Davis-Besse Nuclear Power Station. The Petition seeks, among other things, suspension of the Davis-Besse operating license. A June 2, 2004 ASLB denial of the petition was appealed to the NRC. FENOC and the NRC staff filed opposition briefs on June 24, 2004. If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability or is otherwise made subject to enforcement action based on the Davis-Besse outage, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition and results of operations.
On August 12, 2004, the NRC publicly disclosed that it was notifying FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. OE, CEI, TE and Penn own and/or lease the Perry Nuclear Power Plant. The NRC noted that the plant continues to operate safely. The increased oversight will include an extensive NRC team inspection to access the equipment problems and FirstEnergy’s corrective actions. The outcome of this increased oversight is not known at this time.
Other Legal Matters
Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations are pending against FirstEnergy and its subsidiaries. The most significant not otherwise discussed above are described below.
On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC’s Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies and the Davis-Besse extended outage has become the subject of a formal order of investigation. The SEC’s formal order of investigation also encompasses issues raised
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during the SEC’s examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
Various legal proceedings alleging violations of federal securities laws and related state laws were filed against FirstEnergy in connection with, among other things, the restatements in August 2003 by FirstEnergy and the Ohio Companies of previously reported results, the August 14, 2003 power outages described above, and the extended outage at the Davis-Besse Nuclear Power Station. The lawsuits were filed against FirstEnergy and certain of its officers and directors. On July 27, 2004, FirstEnergy announced that it had reached an agreement to resolve these pending lawsuits. The settlement agreement, which does not constitute any admission of wrongdoing, provides for a total settlement payment of $89.9 million. Of that amount, FirstEnergy’s insurance carriers will pay $71.92 million, based on a contractual pre-allocation, and FirstEnergy will pay $17.98 million, which resulted in an after-tax charge against FirstEnergy’s second quarter and year-to-date 2004 earnings of $11 million or $0.03 per share of common stock (basic and diluted). The settlement has been preliminarily approved by the court with a final hearing scheduled for mid-December 2004. Although not anticipated to occur, in the event that a significant number of shareholders do not accept the terms of the settlement, FirstEnergy and individual defendants have the right, but not the obligation, to set aside the settlement and recommence the litigation.
On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville. Under the FERC’s decision, CEI may be responsible for a portion of new energy market charges imposed by the MISO when its energy markets begin in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. The impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service, the startup date for the MISO energy market, and the resolution of the rehearing request, and cannot be determined at this time.
If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the above matters, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition and results of operations.
4 — PENSION AND OTHER POSTRETIREMENT BENEFITS:
The components of FirstEnergy’s net periodic pension cost, including amounts capitalized, consisted of the following:
In September 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan. Prior to this contribution, projections indicated that cash contributions of approximately $600 million would have been required during the 2006 to 2007 time period under minimum funding requirements established by the IRS. The election to pre-fund the plan is expected to eliminate that funding requirement. Since the contribution is deductible for tax purposes, the after-tax cash impact of the voluntary contribution is approximately $300 million. The payment was funded by FirstEnergy’s subsidiaries through existing short-term credit arrangements, including available intercompany money pools, as follows:
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The components of FirstEnergy’s net periodic other postretirement benefit cost, including amounts capitalized, consisted of the following:
FirstEnergy contributed $17 million to its other postretirement benefit plans in the nine months ended September 30, 2004. The Company has no funding requirements for the remainder of 2004.
Pension and postretirement benefit obligations are allocated to the subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension costs, including amounts capitalized, recognized by each of the Companies in the three and nine months ended September 30, 2004 and 2003 were as follows:
The net periodic postretirement benefit costs, including amounts capitalized, recognized by each of the Companies in the three and nine months ended September 30, 2004 and 2003 were as follows:
Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 because of a plan amendment during the quarter, which required remeasurement of the plan’s obligations. The plan amendment, which increases cost-sharing by employees and retirees effective January 1, 2005, reduced postretirement benefit costs during the three months and nine months ended September 30, 2004, by $13 million and $35 million, respectively.
Consistent with the guidance in FSP 106-2 issued May 19, 2004, FirstEnergy recognized a reduction of $318 million in the accumulated postretirement benefit obligation as a result of the federal subsidy provided under the Medicare Act related to benefits for past service. The subsidy reduced net periodic postretirement benefit costs during the three months and nine months ended September 30, 2004, as follows:
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The impact of the subsidy was not material to the financial statements of each of the Companies for the three and nine months ended September 30, 2004.
5 - DIVESTITURES:
FirstEnergy completed the sale of its international operations during the quarter ended March 31, 2004 with the sales of its remaining 20.1% interest in Avon on January 16, 2004, and its 28.67% interest in TEBSA on January 30, 2004. Impairment charges related to Avon and TEBSA were recorded in the fourth quarter of 2003 and no gain or loss was recognized upon the sales in 2004. Avon, TEBSA and other international assets sold in 2003 were originally acquired as part of FirstEnergy’s November 2001 merger with GPU.
FirstEnergy completed the sale of its 50% interest in GLEP on June 23, 2004. Proceeds of $220 million included cash of $200 million and the right, valued at $20 million, to participate for up to a 40% interest in future wells in Ohio. This transaction produced an after-tax loss of $7 million, or $0.02 per share of common stock, including the benefits of prior tax capital losses that had been previously fully reserved, which offset the capital gain from the sale.
6 - REGULATORY MATTERS:
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation contain similar provisions that are reflected in the Companies’ respective state regulatory plans. These provisions include:
However, despite these similarities, the specific approach taken by each state and for each of the Companies varies.
Reliability Initiatives
On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting a review of various reliability practices. The Company response confirmed that its review was completed and that various enhancements were underway to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts, a portion of which were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. FirstEnergy’s detailed implementation plan was endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives recommended by NERC were certified as complete by June 30, 2004, with one minor exception related to reactive testing of certain generators expected to be completed later in 2004.
On February 26 and 27, 2004, certain FirstEnergy companies, as part of a NERC review of control area operations throughout the United States, participated in a NERC Control Area Readiness Audit. The final audit report, completed on May 6, 2004, identified positive observations and included various recommendations for reliability improvement. FirstEnergy reported completion of those recommendations on June 30, 2004, with one exception related to MISO’s implementation of a voltage stability tool expected to be completed later this year.
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On April 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outages. The Final Report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force recommendations that were directed toward FirstEnergy and reported completion of those activities on June 30, 2004.
With respect to each of the foregoing initiatives, FirstEnergy requested and NERC provided, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. NERC further assembled an independent verification team to confirm implementation of the foregoing initiatives required to be completed as of June 30, 2004. The NERC Verification Team reported, on July 14, 2004, that FirstEnergy has completed the recommended policies, procedures and actions required to be completed by June 30, 2004 or summer 2004, with exceptions noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment.
On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. – Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy’s control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding.
On April 22, 2004, FirstEnergy filed with the FERC the results of the FERC-ordered independent study of part of Ohio’s power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summers 2004 and 2009. Certain requested additional clarifications were provided to the FERC in October 2004. FirstEnergy completed the implementation of recommendations relating to 2004 by June 30, 2004, and is continuing to review results related to 2009. The estimated capital expenditures required by 2009 are not expected to have a material adverse effect on FirstEnergy’s financial results. FirstEnergy notes, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures.
In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and required additional reporting on reliability. The PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order approving the revised reliability benchmark and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. The Order permitted Pennsylvania utilities to file in a separate proceeding to revise the recomputed benchmarks and standards if they have evidence, such as the impact of automated outage management systems, on the accuracy of the PPUC computed reliability indices. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards due to their implementation of automated outage management systems following restructuring. No procedural schedule or hearing date has been set for this proceeding. FirstEnergy is unable to predict the outcome of this proceeding.
On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed’s, Penelec’s and Penn’s “service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring” in Pennsylvania. Hearings were held in early August 2004. On September 30, 2004, Met-Ed, Penelec and Penn filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settlement, Met-Ed, Penelec and Penn agreed to enhance service reliability, performance reporting and communications with customers and to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. In November 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.
Ohio
In July 1999, Ohio’s electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers’ bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The recovery period extension is related to the customer shopping incentives recovery discussed below. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility’s transition plan application.
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In July 2000, the PUCO approved FirstEnergy’s transition plan for the Ohio Companies as modified by a settlement agreement with major parties to the transition plan. The application of SFAS 71 to OE’s generation business and the nonnuclear generation businesses of CEI and TE was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $4.0 billion net of deferred income taxes (OE–$1.6 billion, CEI–$1.6 billion and TE–$0.8 billion) and transition costs related to regulatory assets as filed of $2.9 billion net of deferred income taxes (OE–$1.0 billion, CEI–$1.4 billion and TE–$0.5 billion), with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.4 billion, net of deferred income taxes, (OE–$1.0 billion, CEI–$0.2 billion and TE–$0.2 billion) of impaired generating assets recognized as regulatory assets as described further below, $2.4 billion, net of deferred income taxes, (OE–$1.2 billion, CEI–$0.4 billion and TE–$0.8 billion) of above market operating lease costs and $0.8 billion, net of deferred income taxes, (CEI–$0.5 billion and TE–$0.3 billion) of additional plant costs that were reflected on CEI’s and TE’s regulatory financial statements.
Also as part of the settlement agreement, FirstEnergy gives preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 MW of generation capacity through 2005 at established prices for sales to the Ohio Companies’ retail customers. Customer prices are frozen through the five-year market development period, which runs through the end of 2005, except for certain limited statutory exceptions, including the 5% reduction referred to above.
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 through an extension of the regulatory transition charge. Under the modified Rate Stabilization Plan described below, the deferred incentives and deferred interest costs related to the incentives will be amortized on a dollar-for-dollar basis as the associated revenues are recognized.
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:
Under that proposal, the Ohio Companies requested:
On February 23, 2004, after consideration of the PUCO Staff comments and testimony as well as those provided by some of the intervening parties, the Ohio Companies made certain modifications to the Rate Stabilization Plan. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process on or before December 1, 2004. In addition to requiring the competitive bid process, the PUCO made other modifications to the Ohio Companies’ revised Rate Stabilization Plan application. Among the major modifications were the following:
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On June 18, 2004, the Ohio Companies filed with the PUCO an application for rehearing of the modified version of the Rate Stabilization Plan. Several other parties also filed applications for rehearing. On August 4, 2004, the PUCO issued an Entry on Rehearing modifying its June 9, 2004 Order. The modifications included the following:
On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. The Ohio Companies retain the right to withdraw the modified Rate Stabilization Plan should subsequent adverse action be taken by the PUCO or a court. In the second quarter of 2004, the Ohio Companies implemented the accounting modifications contained in the PUCO’s June 9, 2004 Order, which are consistent with the PUCO’s August 4, 2004 Entry on Rehearing. Those modifications included amortization of transition costs based on extended amortization periods (that are no later than 2007 for OE, mid-2009 for CEI and mid-2008 for TE) and the deferral of interest costs on the accumulated deferred shopping incentives. On October 1, 2004, the OCC filed an appeal with the Ohio Supreme Court to overturn the June 9, 2004 PUCO order.
The Ohio Companies filed a proposed competitive bid process which the PUCO modified on October 6, 2004. The PUCO approved the rules for the competitive bid process setting a three-year supply period (2006-2008) requirement for generation service suppliers and a load cap for individual suppliers. In mid-October, the initial auction schedule was revised so that Part 1 and Part 2 auction bidder applications are due November 4, 2004 and November 15, respectively, the trial auction is scheduled to occur on December 3, the auction would commence December 8 and the PUCO will accept or reject auction results within two business days after the completion of the auction. FirstEnergy has elected to not participate in the auction.
Transition Cost Amortization
OE, CEI and TE amortize transition costs (see Regulatory Matters – Ohio) using the effective interest method. Under the Rate Stabilization Plan as approved above, total transition cost amortization is expected to approximate the following for 2004 through 2009:
The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization plans. These regulatory assets totaling $556 million as of September 30, 2004 (OE - $205 million, CEI - $271 million, TE - $80 million) will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new regulatory
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assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized in each period.
New Jersey
JCP&L’s 2001 Final Decision and Order (Final Order) with respect to its rate unbundling, stranded cost and restructuring filings confirmed rate reductions set forth in its 1999 Summary Order, which had been in effect at increasing levels through July 2003. The Final Order also confirmed the establishment of a non-bypassable SBC to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable MTC primarily to recover stranded costs. The NJBPU has deferred making a final determination of the net proceeds and stranded costs related to prior generating asset divestitures until JCP&L’s request for an IRS ruling regarding the treatment of associated federal income tax benefits is acted upon. Should the IRS ruling support the return of the tax benefits to customers, there would be no effect to FirstEnergy’s or JCP&L’s net income since the contingency existed prior to the merger and there would be an adjustment to goodwill.
In addition, the Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. Under NJBPU authorization in 2002, JCP&L issued through its wholly owned subsidiary, JCP&L Transition, $320 million of transition bonds (recognized as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets) which securitized the recovery of these costs and which provided for a usage-based non-bypassable TBC to cover debt service on the bonds.
Prior to August 1, 2003, JCP&L’s PLR obligation to provide BGS to non-shopping customers was supplied almost entirely from contracted and open market purchases. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates. As of September 30, 2004, the accumulated deferred cost balance totaled approximately $404 million, after the charge discussed below. The NJBPU also allowed securitization of JCP&L’s deferred balance to the extent permitted by law upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization.
Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L’s two August 2002 rate filings requested increases in base electric rates of approximately $98 million annually and requested the recovery of deferred energy costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision, which reduced JCP&L’s annual revenues by approximately $62 million effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L’s rate base for the subsequent six to twelve months. During that period, the decision also required that, within approximately one year of its issuance, JCP&L would initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that Phase II proceeding, the NJBPU could increase JCP&L’s return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L’s service. Any reduction would be retroactive to August 1, 2003. The net revenue decrease from the NJBPU’s decision consists of a $223 million decrease in the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC. The decision in the deferred balances proceeding disallowed $153 million of deferred energy costs, so that the MTC allows for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis. As a result, JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and $32 million of other disallowed regulatory assets. JCP&L filed an interim 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. In its final decision and order issued on May 17, 2004, the NJPBU clarified the method for calculating interest attributable to the cost disallowances, resulting in a $5.4 million reduction from the amount estimated in 2003. On June 1, 2004, JCP&L filed with the NJBPU a supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances, (2) the capital structure including the rate of return, (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning. All other issues included in JCP&L’s amended motion were denied. Oral arguments were held on August 4, 2004. Management is unable to predict when a decision may be reached by the NJBPU.
On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey shore. The NJBPU instituted an investigation into these outages, and directed that a Special Reliability Master (SRM) be hired to oversee the investigation. On December 8, 2003, the SRM issued his Interim Report recommending that JCP&L implement a series of actions to improve reliability in the area affected by the outages. The
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NJBPU adopted the findings and recommendations of the Interim Report on December 17, 2003, and ordered JCP&L to implement the recommended actions on a staggered basis, with initial actions to be completed by March 31, 2004. In late 2003, in accordance with a Settlement Stipulation concerning an August 2002 storm outage, the NJBPU engaged Booth & Associates to conduct an audit of the planning, operations and maintenance practices, policies and procedures of JCP&L. The audit was expanded to include the July 2003 outage and was completed in January 2004. On June 9, 2004, the NJBPU approved a stipulation that incorporated the final SRM report and portions of the final Booth report. The final order was issued by the NJBPU on July 23, 2004.
On July 16, 2004, JCP&L filed the Phase II rate filing with the NJBPU which requested an increase in base rates of $36 million, reflecting the recovery of system reliability costs and a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. Discovery/settlement conferences are ongoing. The filing fulfills the NJBPU requirement that a Phase II proceeding be conducted and that any expenditures and projects undertaken by JCP&L to increase its system reliability be reviewed.
JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balances with the exception of 300 MW from JCP&L’s must run NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order. The BGS auction for periods beginning June 1, 2004 was completed in February 2004 and new BGS tariffs reflecting the auction results became effective June 1, 2004. On May 25, 2004, the NJBPU issued an order adopting a schedule for the BGS post transition year three process. JCP&L filed its proposal suggesting how BGS should be procured for year three and beyond. The NJBPU decision on the filing was announced on October 22, 2004, approving with minor modifications the BGS procurement process filed by JCP&L and the other New Jersey electric distribution companies and authorizing the continued use of NUG committed supply to serve 300 MW of BGS load. The auction is scheduled to take place in February 2005 for the supply period beginning June 1, 2005.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study prepared by TLG Services, Inc. (see Note 2 — Asset Retirement Obligations). This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study.
Pennsylvania
The PPUC authorized in 1998 rate restructuring plans for Penn, Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in Met-Ed’s and Penelec’s 1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Similar to JCP&L’s situation, if the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to FirstEnergy’s, Met-Ed’s or Penelec’s net income since the contingency existed prior to the merger and would be an adjustment to goodwill.
In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later denied in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision also affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. FirstEnergy established reserves in 2002 for Met-Ed’s and Penelec’s PLR deferred energy costs which aggregated $287.1 million, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. As a result, FirstEnergy recorded in 2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to income for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million.
On April 2, 2003, the PPUC remanded the issue relating to merger savings to the Office of Administrative Law for hearings, directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003, voiding the Settlement Stipulation in its entirety and reinstating Met-Ed’s and Penelec’s restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 20, 2001 order in its entirety. The PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective
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upon one day’s notice. In response to that order, Met-Ed and Penelec filed supplements to their tariffs to become effective October 24, 2003.
On October 8, 2003, Met-Ed and Penelec filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC’s findings would not impair their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed and Penelec for the NUG trust fund refund, denying Met-Ed’s and Penelec’s other clarification requests and granting ARIPPA’s petition with respect to the accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC’s finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis.
On October 27, 2003, a Commonwealth Court judge issued an Order denying Met-Ed’s and Penelec’s Objection without explanation. Due to the vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed and Penelec, in order to preserve their rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC’s October 2 and October 16 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed’s and Penelec’s Objection was intended to be denied on the merits. In addition to these findings, Met-Ed and Penelec, in compliance with the PPUC’s Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC’s findings in their Orders.
Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sale agreement. The PLR sale is 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 retains 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.
7 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:
In March 2004, the FASB issued an exposure draft of a new standard, which would amend SFAS 123 and SFAS 95. Among other items, the new standard would require expensing stock options in FirstEnergy’s financial statements. In October 2004, the FASB agreed to delay the effective date of the proposed standard from January 1, 2005 to periods beginning after June 15, 2005, for calendar year companies. FirstEnergy will not be able to determine the impact of the proposed standard on its results of operations until the standard is issued in final form. The impacts of the fair value recognition provisions of SFAS 123 on FirstEnergy’s net income and earnings per share for the current reporting periods are disclosed in Note 2.
In December 2003, the FASB issued an exposure draft of a new standard, which would amend SFAS 128. Among other items, the new standard would eliminate the provisions of SFAS 128 that allow an entity to rebut the presumption that contracts with the option of settling in either cash or stock will be settled in stock. The new standard is expected to be issued in the fourth quarter of 2004 and be effective for all periods ending after December 15, 2004. Retrospective application to all prior-period earnings per share data presented would be required. FirstEnergy is continuing to assess the proposed standard but does not anticipate a material impact on its calculation of earnings per share.
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In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluate its investments as required by existing authoritative guidance.
In March 2004, the FASB ratified the final consensus on Issue 03-16. EITF 03-16 requires that an investment in a limited liability company that maintains a “specific ownership account” for each investor should be viewed as similar to an investment in a limited partnership for determining whether the cost or equity method of accounting should be used. The equity method of accounting is generally required for investments that represent more than a three to five percent interest in a limited partnership. EITF 03-16 was adopted by FirstEnergy in the third quarter of 2004 and did not affect the Companies’ financial statements.
Issued in May 2004, FSP 106-2 provides guidance on accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. The effect of the federal subsidy provided under the Medicare Act on FirstEnergy’s consolidated financial statements is described in Note 4. The impact of the subsidy was not material to the financial statements of each of the Companies for the three and nine months ended September 30, 2004.
In December 2003, the FASB issued a revised interpretation of ARB 51 referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on the consolidated financial statements of FirstEnergy or the Companies.
8 - SEGMENT INFORMATION:
FirstEnergy operates under two reportable segments: regulated services and competitive services. The aggregate “Other” segments do not individually meet the criteria to be considered a reportable segment. “Other” consists of interest expense related to holding company debt; corporate support services and the international businesses acquired in the 2001 merger. FirstEnergy’s primary segment is its regulated services segment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOC in Ohio, Pennsylvania and New Jersey. The competitive services business segment consists of the subsidiaries (FES, FSG, MYR and FirstCom) that operate unregulated energy and energy-related businesses, including the operation of FirstEnergy’s generation facilities resulting from the deregulation of the Companies’ electric generation business (see Note 6 – Regulatory Matters). The regulated services segment designs, constructs, operates and maintains FirstEnergy’s regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition costs recovery.
The competitive services segment has responsibility for FirstEnergy generation operations as discussed under Note 6. As a result, its revenues include all generation electric sales revenues (including the generation services to regulated franchise customers who have not chosen an alternative generation supplier) and all domestic unregulated energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation and sourcing of commodity requirements, providing local and long-distance phone service, as well as other competitive energy-application services.
Segment reporting in 2003 was reclassified to conform with the current year business segment organizations and operations. Revenues from the competitive services segment now include all generation revenues including generation services to regulated franchise customers previously reported under the regulated services segment and now exclude revenues from power supply agreements with the regulated services segment previously reported as internal revenues. The regulated services segment results now exclude generation sales revenues and related generation commodity costs. Certain amounts (including transmission and congestion charges) were reclassified among purchased
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power, other operating costs and depreciation and amortization to conform with the current year presentation of generation commodity costs. Segment results for 2003 have been adjusted to reflect the reclassification of revenue, expense, interest expense and tax amounts of divested businesses reflected as discontinued operations (see Note 2) and certain revenues and expenses have been reclassified and presented on a net basis to conform with the current year presentation (see Note 1).
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Segment Financial Information
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting:
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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME(Unaudited)
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME(Unaudited)
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CONSOLIDATED BALANCE SHEETS(Unaudited)
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these balance sheets.
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Report of Independent Registered Public Accounting Firm
To the Stockholders and Board ofDirectors of FirstEnergy Corp.:
We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of September 30, 2004, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 the standards of the Public Company Accounting Oversight Board, 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 the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholders’ equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(F) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 9 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLPCleveland, OhioNovember 2, 2004
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MANAGEMENT’S DISCUSSION AND ANALYSIS OFRESULTS OF OPERATIONS AND FINANCIAL CONDITION
EXECUTIVE SUMMARY
Net income in the third quarter of 2004 was $299 million, or basic and diluted earnings of $0.91 per share of common stock, compared to net income of $153 million, or basic earnings of $0.51 per share of common stock ($0.50 diluted) for the third quarter of 2003. FirstEnergy’s third quarter earnings reflect solid progress – particularly in the areas of lower financing costs and improvements in power generation and energy delivery operations. Net income in the first nine months of 2004 was $677 million, or basic earnings of $2.07 per share ($2.06 diluted), compared to $313 million, or basic earnings of $1.06 per share ($1.05 diluted) for the first nine months of 2003. Earnings in the third quarter and first nine months of 2004 were reduced on a per share basis from the issuance and sale of 32.2 million shares of common stock in the third quarter of 2003. The additional shares reduced earnings by $0.09 per share of common stock (basic and diluted) in the third quarter of 2004 and reduced basic and diluted earnings by $0.22 per share of common stock in the first nine months of 2004.
Milder weather during the third quarter of 2004 led to overall flat kilowatt-hour deliveries compared with the year-prior quarter, including a negative impact on residential customers because of lower air-conditioning use. Despite the milder weather, FirstEnergy’s generation fleet continued to show improved performance, enabling FirstEnergy to take advantage of additional spot market sales. The fleet posted a record output in the third quarter and the first nine months of 2004.
FirstEnergy’s pension and other post-employment benefits expenses decreased by $29 million in the third quarter of 2004 compared to the same period last year, due to higher trust asset values, revisions to its health care benefits plan, and the positive effect from the new Medicare Act enacted in December 2003. The same factors contributed to a $77 million decrease in the first nine months of 2004, compared to the same period in 2003.
FirstEnergy’s debt paydown and refinancing program reduced debt by $982 million during the first nine months of 2004 which is expected to produce annualized savings of approximately $79 million. FirstEnergy remains on track to achieve its goal of reducing debt by at least $1 billion this year. FirstEnergy also improved its financial flexibility with the replacement of $1 billion of its credit commitments that, combined with other existing credit facilities, brings the total capacity of FirstEnergy’s primary credit facilities and those of its subsidiaries to $2.3 billion.
On August 5, 2004, the Ohio Companies accepted the Ohio Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In addition to providing enhanced customer benefits, the approved plan adequately addressed most of the issues raised by FirstEnergy. Those issues included the ability to seek recovery of increased fuel costs and terms for offering market support generation. In the second quarter of 2004, FirstEnergy implemented the accounting modifications approved by the PUCO in its initial Rate Stabilization Plan order. On October 1, 2004, the OCC filed an appeal with the Ohio Supreme Court to overturn the June 9, 2004 PUCO order.
The Ohio Companies filed a proposed competitive bid process which the PUCO modified on October 6, 2004. The PUCO approved the rules for the competitive bid process setting a three-year supply period (2006-2008) requirement for generation service suppliers and a load cap for individual suppliers. In mid-October, the initial auction schedule was revised so that Part 1 and Part 2 auction bidder applications are due November 4, 2004 and November 15, respectively, the trial auction is scheduled to occur on December 3, the auction commences December 8 and the PUCO will accept or reject auction results within two business days after the completion of the auction. FirstEnergy has elected to not participate in the auction.
In September 2004, FirstEnergy and its subsidiaries made a $500 million voluntary contribution to their pension plan to eliminate funding requirements that were projected in 2006 and 2007. The net after-tax cost of the contribution is approximately $300 million and is expected to be accretive to earnings over the next three years. In addition, the contribution is expected to reduce FirstEnergy’s overall risk profile, because it reduces uncertainty regarding the plan’s unfunded liability.
On July 27, 2004, FirstEnergy announced that it had reached an agreement to resolve various pending legal proceedings filed against FirstEnergy and certain of its officers and directors, alleging violations of federal securities laws and related state laws (see Outlook – Other Legal Matters below) in connection with financial restatements of previously reported results in August 2003, by FirstEnergy and the Ohio Companies, the August 14, 2003 regional power outages and the extended outage at the Davis-Besse Nuclear Power Station. The settlement agreement, which does not constitute an admission of wrongdoing, provides for a total settlement payment of $89.9 million, of which
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FirstEnergy’s insurance carrier will pay $71.92 million. FirstEnergy’s portion of $17.98 million, resulted in an after-tax charge of $11 million or $0.03 per share of common stock (basic and diluted) in FirstEnergy’s second quarter and year-to-date 2004 earnings. The settlement was preliminarily approved by the court with a final hearing scheduled for mid-December 2004.
FirstEnergy continues to participate in meaningful settlement negotiations with the EPA and other parties to the New Source Review case involving the W. H. Sammis Plant (see Outlook - Environmental Matters). As a result, the U.S. District Court judge hearing the case rescheduled the date for the remedy phase of the trial to January 2005.
FIRSTENERGY’S BUSINESS
FirstEnergy Corp. is a registered public utility holding company headquartered in Akron, Ohio that provides regulated and competitive energy services (see Results of Operations – Business Segments). FirstEnergy continues to pursue its goal of being the leading supplier of energy and related services in portions of the Midwest and mid-Atlantic regions of the United States, where it sees the best opportunities for growth. FirstEnergy’s fundamental business strategy remains stable and unchanged. While FirstEnergy continues to build toward a strong regional presence, key elements for its strategy are in place and management’s focus continues to be on execution. FirstEnergy intends to continue providing competitively priced, high-quality products and value-added services – energy sales and services, energy delivery, power supply and supplemental services related to its core business. As the industry continues to evolve, FirstEnergy has taken and expects to take actions designed to compete in the changing energy marketplace. FirstEnergy’s eight electric utility operating companies provide transmission and distribution services and comprise the nation’s fifth largest investor-owned electric system, serving 4.4 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey.
Competitive services are principally provided by FES, FSG, MYR and FirstEnergy’s majority owned subsidiary, FirstCom. Services provided through these subsidiaries include heating, ventilation, air-conditioning, refrigeration, process piping, plumbing, electrical and facility control systems and high-efficiency electrotechnologies. Telecommunication services such as local and long-distance telephone service are also provided to more than 65,000 customers. While competitive revenues have increased since 2001, regulated energy services continue to provide, in aggregate, the majority of FirstEnergy’s revenues and earnings.
Beginning in 2001, Ohio utilities that offered both competitive and regulated retail electric services were required to implement a corporate separation plan approved by the PUCO – one which provided a clear separation between regulated and competitive operations. FES provides competitive retail energy services while the EUOC provide regulated transmission and distribution services. FGCO, a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and operates those plants. Under the terms of the Ohio Rate Stabilization Plan, the deadline for achieving structural separation by transferring the ownership of applicable EUOC generating assets to a competitive affiliate was extended until twelve months after the termination of the Rate Stabilization Plan, unless otherwise extended further by the PUCO, or until December 31, 2008, whichever is earlier. All of the EUOC power supply requirements for the Ohio Companies and Penn are provided by FES.
FirstEnergy acquired international assets through its merger with GPU in November 2001. GPU Capital and its subsidiaries provided electric distribution services in foreign countries (see Results of Operations – Discontinued Operations). GPU Power and its subsidiaries owned and operated generation facilities in foreign countries. As of January 30, 2004, substantially all of the international operations had been divested (see Note 5) – reflecting FirstEnergy’s commitment to focus on its core electric business.
FirstEnergy’s current focus includes: (1) continuing safe operations; (2) enhancing customer service; (3) optimizing its generation portfolio; (4) minimizing unplanned extended generation outages; (5) effectively managing commodity supplies and risks; (6) reducing its cost structure; (7) enhancing its credit profile and financial flexibility; and (8) managing the skills and diversity of its workforce.
RECLASSIFICATIONS
As further discussed in Notes 1 and 8 to the Consolidated Financial Statements, amounts for purchased power, other operating costs and provisions for depreciation and amortization in FirstEnergy’s 2003 Consolidated Statements of Income were reclassified to conform with the current year presentation of generation commodity costs. These reclassifications did not change previously reported results in 2003. Business segment reporting in 2003 was reclassified to conform with the current year business organizations and operations (see Note 8). In addition, as discussed in Note 2 to the Consolidated Financial Statements, reporting of discontinued operations also resulted in the reclassification of revenues, expenses and taxes and certain revenues and expenses have been reclassified and presented on a net basis to conform with the current year presentation.
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RESULTS OF OPERATIONS
The increase in net income of $146 million in the third quarter and $364 million in the first nine months of 2004 reflects higher income from continuing operations of $147 million and $400 million, respectively, when current period results are compared to those of 2003. A significant portion of the third quarter and year-to-date improvement resulted from the absence of a goodwill impairment charge recognized in 2003, lower energy delivery and nuclear production costs and reduced interest expense. These positive factors were offset in part by the impact of mild summer weather and losses recognized on the sale of securities and impairment of several partnership investments. A significant portion of the improvement in the first nine months of 2004 was the absence of a $172 million charge incurred in 2003 for costs disallowed in the JCP&L rate case decision of July 2003. The first nine months of 2003 also included an after-tax charge of $67 million resulting from the abandonment of FirstEnergy’s shares in Emdersa’s parent company, GPU Argentina Holdings, Inc. and an after-tax credit of $102 million resulting from the cumulative effect of an accounting change due to the adoption of SFAS 143.
The results for the three and nine months ended September 30, 2004 and 2003 are summarized in the table below.
Results of Operations – Third Quarter of 2004 Compared with the Third Quarter of 2003
Total revenues increased $113 million in the third quarter of 2004. The sources of changes in total revenues are summarized in the following table:
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Changes in electric generation kilowatt-hour sales and distribution deliveries in the third quarter of 2004 are summarized in the following table:
Retail sales by FirstEnergy’s EUOC remain the largest source of revenues, contributing more than 70% of electric revenues and over 60% of total revenues. The following major factors contributed to the $63 million decrease in retail electric revenues from FirstEnergy’s EUOC in the third quarter of 2004.
Reduced customer usage and lower rates contributed to a $63 million decrease ($52 million of distribution deliveries and $11 million of generation) in EUOC retail electric revenues in the third quarter of 2004, compared to the third quarter of 2003. Lower usage due to cooler weather and alternative energy suppliers providing a larger portion of franchise customer energy requirements more than offset the effects of a stronger economy on demand. Alternative energy suppliers provided 24.0% of the total energy delivered to retail customers in the third quarter of 2004, compared to 22.9% in the same period of 2003. Lower prices resulted from two factors — a shopping credit rate increase in Ohio and a change in the mix of sales with a smaller proportion of residential distribution deliveries (relative to commercial and industrial deliveries) and fewer retail customers receiving generation in Ohio. Partially offsetting the lower rates due to the changing mix of sales primarily in Ohio were increased rates at JCP&L resulting from higher energy, MTC and SBC rates; the increases in energy rates and MTC are concentrated in the summer billing months. The increase in JCP&L energy, MTC and SBC rates were moderated by lower base distribution rates due to the July 25, 2003, NJBPU base electric rate proceeding decision (see Regulatory Matters — New Jersey) effective August 1, 2003.
Electric sales by FES increased by $120 million from additional sales to the wholesale market which increased $132 million in the third quarter of 2004. Higher electric sales to the wholesale market resulted in part from nuclear generation increasing 45% (fossil generation decreased 8%), primarily as a result of the Davis-Besse restart and fewer outages in 2004, which increased total available generation by 8%.
FirstEnergy’s regulated and unregulated subsidiaries record purchase and sales transactions with PJM on a gross basis in accordance with EITF 99-19. This gross basis classification of revenues and costs may not be comparable to other energy companies that operate in regions that have not established ISOs and do not meet EITF 99-19 criteria. The aggregate purchase and sales transactions for the three months ended September 30, 2004 and 2003 are summarized as follows:
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FirstEnergy’s revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from PJM from power sales (as reflected in the table above) during periods when it had additional available power. Revenues also include sales by FirstEnergy of power sourced from PJM (reflected as purchases in the table above) during periods when it required additional power to meet FirstEnergy’s retail load requirements and, secondarily, to sell to the wholesale market.
Transmission revenues increased $75 million ($29 million net of related expenses), primarily reflecting transactions with MISO, which began operations in December 2003 through the pooling of transmission capacity of Midwestern utilities to provide unbundled, regional transmission services for electric utilities.
Natural gas sales were $3 million lower (excluding the GLEP partnership interest) due to decreased volumes. Lower than anticipated margins and higher administrative costs resulted in FES exiting customer choice markets as contracts expired. FES scaled back its participation in the natural gas wholesale market due to increasing volatility and risk associated with that business.
The generation margin in the third quarter of 2004 improved by $32 million compared to the same period in 2003 and the ratio of generation margin to revenue remained nearly unchanged. Higher electric generation sales resulted principally from the additional sales in the wholesale market. The gas margin increased $5 million despite lower sales volumes due to better unit margins on sales to commercial and industrial customers.
Income before income taxes, discontinued operations and the cumulative effect of an accounting change increased $228 million in the third quarter of 2004. In addition to the impact of improved electric and gas margins discussed above, the following factors contributed to the increase in income before taxes:
Partially offsetting the above sources of improved earnings were two factors:
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Net income in the third quarter of 2003 included $1 million of after-tax earnings reflecting reclassification of revenues and expenses associated with discontinued operations of FirstEnergy’s Bolivia business and FSG subsidiaries - - Colonial Mechanical, Webb Technologies and Ancoma, Inc.
Postretirement Plans
Strengthened equity markets, amendments to FirstEnergy’s health care benefits plan in the first quarter of 2004 and the Medicare Act signed by President Bush in December 2003 combined to reduce pension and other postemployment benefits costs. Combined, these employee benefit expenses decreased by $29 million in the third quarter of 2004. The following table summarizes the net pension and OPEB expense for the three months ended September 30, 2004 and 2003.
The decrease in pension and OPEB expenses are included in various cost categories and have contributed to other cost reductions discussed above. See “Critical Accounting Policies – Pension and Other Postretirement Benefits Accounting” for a discussion of the impact of underlying assumptions on postretirement benefits expenses.
Results of Operations – First Nine Months of 2004 Compared with the First Nine Months of 2003
Total revenues increased $372 million in the first nine months of 2004. The sources of changes in total revenues are summarized in the following table:
Changes in electric generation kilowatt-hour sales and distribution deliveries in the first nine months of 2004 are summarized in the following table:
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The following major factors contributed to the $125 million reduction in retail electric revenues from FirstEnergy’s EUOC in the first nine months of 2004.
Reductions in both customer usage and prices contributed to lower EUOC retail electric revenues. Customers shopping in FirstEnergy’s franchise areas for alternative energy suppliers remained the largest single factor reducing usage. Alternative suppliers provided 24.3% of the total energy delivered to retail customers in the first nine months of 2004, compared to 21.1% in the same period of 2003. A stronger economy only partially offset the combined effects of mild summer weather in the third quarter of 2004, compared to the same period of 2003, and reduced usage due to alternative energy suppliers providing a larger portion of franchise customer energy requirements. Lower prices resulted from three factors — a shopping credit rate increase in Ohio, a change in the mix of sales with fewer retail customers receiving generation in Ohio, and lower base distribution rates at JCP&L. Partially offsetting JCP&L’s lower base distribution rates were higher energy, MTC and SBC rates; the increases in energy rates and MTC are concentrated in the summer billing months. EUOC sales to wholesale customers decreased by $82 million on a 20% reduction in kilowatt-hour sales – JCP&L’s sales represented substantially all of the decrease.
Electric sales by FES increased by $576 million primarily from additional spot sales in the wholesale market which increased $496 million for the first nine months of 2004. Higher electric sales to the wholesale market were possible due in part to a net 13% increase in generation, which was available from the combination of an increase in FirstEnergy’s nuclear generating plants (48% increase) offset in part by lower fossil generation (2% decrease). Retail sales increased by $80 million, primarily from customers within FirstEnergy’s Ohio franchise areas switching to FES under Ohio’s electricity choice program.
FirstEnergy’s regulated and unregulated subsidiaries record purchase and sales transactions with PJM on a gross basis in accordance with EITF 99-19. This gross basis classification of revenues and costs may not be comparable to other energy companies that operate in regions that have not established ISOs and do not meet EITF 99-19 criteria. The aggregate purchase and sales transactions for the nine months ended September 30, 2004 and 2003 are summarized as follows:
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(1) Certain prior year energy sales and purchases amounts have been reclassified to transmission revenues and expenses (see Note 8).
Transmission revenues increased $212 million ($66 million net of related expenses), primarily reflecting transactions with MISO, which began operations in December 2003 through the pooling of transmission capacity of Midwestern utilities to provide unbundled regional transmission services for electric utilities.
Natural gas sales decreased $99 million (excluding the GLEP partnership interest) primarily due to the expiration of FES customer choice contracts and reduced sales to the wholesale market. Lower than anticipated margins and higher administrative costs resulted in FES exiting customer choice markets as contracts expired. FES scaled back its participation in the natural gas wholesale market due to increasing volatility and risk associated with that business. Lower sales to large commercial and industrial customers in the first nine months of 2004, compared to the same period in 2003, primarily reflected fewer customers.
The generation margin in the first nine months of 2004 improved by $307 million compared to the same period in 2003 as electric generation revenues increased faster than the related costs for fuel and purchased power. Excluding the impact of the July 2003 JCP&L rate decision discussed above, the generation margin increased $154 million and the ratio of generation margin to revenue improved from 25.3% to 25.9%, reflecting additional lower-cost nuclear generation. Higher electric generation sales resulted principally from the additional sales to the wholesale market. The gas margin increased $2 million from reduced costs.
Income before income taxes, discontinued operations and the cumulative effect of an accounting change increased $662 million in the first nine months of 2004. In addition to the impact of improved electric and gas margins discussed above, the following factors contributed to the increase in income before taxes:
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Partially offsetting the above sources of improved earnings were three factors:
Net income in the first nine months of 2003 included after-tax losses from discontinued operations of $65 million reflecting the reclassification of revenues and expenses associated with divestitures of FirstEnergy’s Argentina and Bolivia businesses, FSG subsidiaries (Colonial Mechanical, Webb Technologies and Ancoma, Inc.) and NEO.
Results in the first nine months of 2003 included an after-tax credit to net income of $102 million recorded upon the adoption of SFAS 143 in January 2003. FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $602 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The ARO liability at the date of adoption was $1.11 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.24 billion. FirstEnergy expects substantially all of its nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn to be recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for those companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $175 million increase to income, or $102 million net of income taxes.
Strengthened equity markets in 2003, amendments to FirstEnergy’s health care benefits plan in the first quarter of 2004 and the Medicare Act signed by President Bush in December 2003 combined to reduce pension and other postemployment benefits costs. Combined, these employee benefit expenses decreased by $77 million in the first nine months of 2004. The following table summarizes the net pension and OPEB expense for the nine months ended September 30, 2004 and 2003.
(1) Excludes the capitalized portion of postretirement benefits costs (see Note 4 for total costs).
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RESULTS OF OPERATIONS — BUSINESS SEGMENTS
FirstEnergy manages its business as two separate major business segments – regulated services and competitive services. In the first quarter of 2004, management made certain changes in presenting results for these two segments (see Note 8). The regulated services segment no longer includes a portion of generation services. The regulated services segment designs, constructs, operates and maintains FirstEnergy’s regulated transmission and distribution systems. Its revenues are primarily derived from the delivery of electricity and transition cost recovery. All generation services are now reported in the competitive services segment. That segment’s revenues include all generation electric sales revenues (including the generation services to regulated franchise customers who have not chosen an alternative generation supplier) and all domestic unregulated energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation, commodity sourcing and other competitive energy-application services such as heating, ventilation and air-conditioning. “Other” consists of interest expense related to holding company debt, corporate support services and the international businesses that were substantially divested by the first quarter of 2004. FirstEnergy’s two major business segments include all or a portion of the following business entities:
Financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results to consolidated financial results is provided in Note 8 to the consolidated financial statements. Net income (loss) by business segment was as follows:
Regulated Services — Third Quarter of 2004 Compared with the Third Quarter of 2003
Financial results for the regulated services segment were as follows:
The change in operating revenues resulted from the following sources:
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\
The net increase in operating revenues resulted from:
Income before discontinued operations and the cumulative effect of an accounting change increased $22 million in the third quarter of 2004 and pre-tax income increased by $34 million from the following factors:
Partially offsetting the above sources of improved earnings were several factors:
Competitive Services — Third Quarter of 2004 Compared with the Third Quarter of 2003
Financial results for the competitive services segment were as follows:
The change in total revenues resulted from the following sources:
The net increase in electric sales resulted from:
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Natural gas sales were $10 million lower primarily due to the sale of GLEP in June 2004. Excluding FirstEnergy’s interest in GLEP from 2003 results, natural gas sales were $3 million lower due to decreased volumes. Lower than anticipated margins and higher administrative costs resulted in FES exiting customer choice markets as contracts expired. FES scaled back its participation in the wholesale market due to increasing volatility and risk associated with that business.
The generation margin increased $32 million. Higher electric generation revenues resulted from additional sales to the wholesale market which were possible due to increased nuclear generation. The margin on gas sales increased $5 million despite lower sales volumes due to better unit margins on sales to commercial and industrial customers using lower supply costs previously dedicated to the customer choice contracts.
Income before discontinued operations and the cumulative effect of an accounting change increased $135 million in the third quarter of 2004 and pre-tax income increased by $211 million. In addition to the effect of improved electric and gas margins discussed above, the following factors contributed to the increase in pre-tax income:
Regulated Services – First Nine Months of 2004 Compared with the First Nine Months of 2003
The increase in operating revenues resulted from:
Income before discontinued operations and the cumulative effect of an accounting change increased $6 million in the first nine months of 2004 and pre-tax income decreased by $5 million. The following factors contributed to the changes:
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Competitive Services – First Nine Months of 2004 Compared with the First Nine Months of 2003
The increase in electric revenues resulted from:
Natural gas sales decreased $105 million primarily due to the expiration of FES customer choice contracts and reduced sales to the wholesale market. Lower than anticipated margins and higher administrative costs resulted in FES exiting customer choice markets as contracts expired. Due to increased volatility and perceived risk, FES reduced its participation in the wholesale market. Decreased sales to large commercial and industrial customers in the first nine months of 2004 primarily reflected fewer customers.
The generation margin increased $307 million as electric generation revenues increased at a greater rate than the related costs for fuel and purchased power. Higher electric generation revenues resulted from additional sales to the wholesale market. Excluding the impact of the July 2003 JCP&L rate decision, as discussed above, the generation margin increased $154 million. The margin on gas sales increased $2 million on reduced sales.
Income before discontinued operations and the cumulative effect of an accounting change increased $420 million in the first nine months of 2004. In addition to the effect of improved generation and gas margins discussed above, the following factors contributed to that increase:
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CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy’s cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing FirstEnergy’s net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next two years, FirstEnergy expects to meet its contractual obligations with cash from operations. Thereafter, FirstEnergy expects to use a combination of cash from operations and funds from the capital markets.
Changes in Cash Position
The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $1.375 billion of revolving credit facilities, ($1.214 billion unused as of September 30, 2004). In the first nine months of 2004, FirstEnergy received $515 million of cash dividends from its subsidiaries and paid $368 million in cash common stock dividends to its shareholders. There are no material restrictions on the issuance of cash dividends by FirstEnergy’s subsidiaries. As of September 30, 2004, FirstEnergy had $68 million of cash and cash equivalents, compared with $114 million as of December 31, 2003. The major source of changes in these balances are summarized below.
Cash Flows From Operating Activities
FirstEnergy’s consolidated net cash from operating activities is provided by its regulated and competitive energy services businesses (see Results of Operations – Business Segments above). Net cash provided from operating activities in the third quarter and first nine months of 2004, compared with the corresponding periods of 2003, were as follows:
Net cash provided from operating activities decreased $314 million in the third quarter of 2004 compared to the same period last year due to a voluntary pension trust contribution of $500 million in the third quarter of 2004. The decrease was partially offset by a $149 million of increased cash earnings, as described above under “Results of Operations.” During the first nine months of 2004, net cash provided from operating activities increased $230 million. The increase in the first nine months of 2004 was due to a $367 million increase from changes in working capital and $363 million of higher cash earnings, partially offset by the $500 million pension trust contribution. The working capital change primarily resulted from a $144 million decrease in receivables (including the net proceeds from the settlement of FirstEnergy’s claim against NRG, Inc. for the terminated sale of four power plants) and a $90 million increase in accrued tax balances.
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Cash Flows From Financing Activities
The following table provides details regarding security issuances and redemptions during the third quarter and first nine months of 2004 and 2003:
Net cash used for financing activities increased by $54 million in the third quarter of 2004 from the third quarter of 2003. The increase in cash used for financing activities resulted primarily from an increase in net redemptions and refinancings of debt and preferred securities and higher dividend payments. Redemption and refinancing activities for debt and preferred stock aggregated approximately $451 million during the third quarter of 2004 (including $25 million of pollution control note repricings). The redemption and refinancing activities and pollution control note repricings are expected to result in annualized savings of $47 million. Net cash used for the above financing activities increased by $512 million in the first nine months of 2004 from the same period of 2003. The increase in cash used for financing activities resulted primarily from the absence of equity financing in 2004 and higher dividend payments offset in part by the net issuance of debt.
FirstEnergy has sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004, aggregating $23 million. These cash requirements are expected to be satisfied from internal cash.
FirstEnergy had approximately $303 million of short-term indebtedness as of September 30, 2004 compared to approximately $522 million as of December 31, 2003. Unused borrowing capability as of September 30, 2004 included the following:
As of September 30, 2004, the Ohio EUOC and Penn had the aggregate capability to issue approximately $4.1 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuances of FMBs by OE and CEI are also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $639 million and $582 million, respectively, as of September 30, 2004. Under the provisions of its senior note indenture, JCP&L may issue additional FMBs only as collateral for senior notes. As of September 30, 2004, JCP&L had
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the capability to issue $490 million of additional senior notes upon the basis of FM collateral. Based upon applicable earnings coverage tests in their respective charters, OE, TE, Penn, and JCP&L could issue a total of $4.0 billion of preferred stock (assuming no additional debt was issued) as of September 30, 2004. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock.
FirstEnergy’s working capital and short-term borrowing needs are met principally with a syndicated $1 billion three-year revolving credit facility maturing in June 2007. Combined with a syndicated $375 million three-year facility for FirstEnergy maturing in October 2006, a $125 million three-year facility for OE maturing in October 2006, and a syndicated $250 million two-year facility for OE maturing in May 2005, FirstEnergy’s primary syndicated credit facilities total $1.75 billion. These revolving credit facilities, combined with an aggregate $550 million of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet the short-term working capital requirements of FirstEnergy and its subsidiaries. Total unused borrowing capability under existing facilities and accounts receivable financing facilities totaled $1.7 billion as of September 30, 2004.
Borrowings under these facilities are conditioned on FirstEnergy and/or OE maintaining compliance with certain financial covenants in the agreements. FirstEnergy and OE are each required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually-defined fixed charge coverage ratio of no less than 2 to 1. FirstEnergy and OE are in compliance with these financial covenants. As of September 30, 2004, FirstEnergy’s and OE’s fixed charge coverage ratios, as defined under the credit agreements, were 4.08 to 1 and 7.36 to 1, respectively. FirstEnergy’s and OE’s debt to total capitalization ratios, as defined under the credit agreements, were 0.55 to 1 and 0.39 to 1, respectively. The ability to draw on each of these facilities is also conditioned upon FirstEnergy or OE making certain representations and warranties to the lending banks prior to drawing on their respective facilities, including a representation that there has been no material adverse change in their business, their condition (financial or otherwise), their results of operations, or their prospects.
FirstEnergy’s and OE’s primary credit facilities contain no provisions restricting their ability to borrow, or accelerating repayment of outstanding loans, as a result of any change in their S&P or Moody’s credit ratings. The primary facilities do contain “pricing grids”, whereby the cost of funds borrowed under the facilities is related to the credit ratings of the company borrowing the funds.
FirstEnergy’s regulated companies have the ability to borrow from each other and FirstEnergy to meet their short-term working capital requirements. A similar but separate arrangement exists among its competitive companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and competitive subsidiaries, as well as proceeds available from bank borrowings. For the regulated companies, available bank borrowings include $1.75 billion from FirstEnergy’s and OE’s revolving credit facilities. For the competitive companies, available bank borrowings include only the $1.375 billion of FirstEnergy’s revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of such loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2004 was 1.28% for the regulated companies’ pool and 1.32% for the competitive companies’ pool.
On September 1, 2004, Penelec redeemed at par $100 million principal amount of its subordinated debentures in connection with the concurrent redemption at par of $100 million principal amount of Penelec Capital Trust 7.34% Trust Preferred Securities.
On July 22, 2004, S&P updated its analysis of U.S. utility FMB in response to changes in the industry. As a result of its revised methodology for evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility companies including JCP&L and Penn. JCP&L’s FMB credit rating was upgraded to BBB+ from BBB and Penn’s FMB credit rating was upgraded to BBB from BBB-.
On August 26, 2004, S&P lowered its rating on certain Met-Ed Senior Notes to BBB- from BBB. The rationale for the ratings change was that Met-Ed’s senior secured notes, in aggregate, now comprise greater than 80% of Met-Ed’s total debt outstanding. According to the terms of the senior note indenture, once the 80% threshold is reached, the collateral mortgage bond security falls away and all senior secured notes that were secured by Met-Ed’s senior note indenture become unsecured. The one notch lower rating reflects this loss of collateral security. The BBB senior secured rating on Met-Ed’s first mortgage bonds remain unchanged.
Also on August 26, 2004, S&P stated that a favorable outcome of the Ohio Rate Stabilization Plan auction process and a favorable resolution of pending environmental litigation would support a higher ratings outlook, or possibly a higher rating. S&P noted that a ratings upgrade in 2004 does not appear likely because those major issues would most likely not be resolved before the end of 2004. On September 14, 2004, S&P stated that FirstEnergy’s $500 million voluntary contribution to its pension plan was credit neutral.
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Cash Flows From Investing Activities
Net cash flows provided from investing activities totaled $5 million in the third quarter of 2004, compared to net cash flows used of $219 million for investing activities for the same period of 2003. The $224 million change resulted from $278 million in cash proceeds from certificates of deposit in the third quarter of 2004.
The following table summarizes investments by FirstEnergy’s regulated services and competitive services segments in the third quarter and first nine months of 2004:
In the last quarter of 2004, capital requirements for property additions and capital leases are expected to be approximately $293 million, including $75 million for nuclear fuel.
FirstEnergy’s current forecast reflects expenditures of approximately $2.3 billion for property additions and improvements from 2004-2006, of which approximately $717 million is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $303 million, of which approximately $90 million applies to 2004. During the same periods, the Companies’ nuclear fuel investments are expected to be reduced by approximately $269 million and $88 million, respectively, as the nuclear fuel is consumed.
GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy and the Companies enter into various agreements 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, 2004, the maximum potential future payments under outstanding guarantees and other assurances totaled approximately $2.1 billion as summarized below:
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FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities — principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by FirstEnergy’s other assets. The likelihood is remote that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate payment of cash collateral or provision of an LOC may be required. The following table summarizes collateral provisions as of September 30, 2004:
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
Various contracts include credit enhancements in the form of cash collateral, letters of credit or other security in the event of a reduction in credit rating. Requirements of these provisions vary and typically require more than one rating reduction to below investment grade by S&P or Moody’s to trigger additional collateralization.
On July 15, 2004, FirstEnergy received $289 million of cash (principal and interest) for maturing OE certificates of deposit. These certificates of deposit related to OE’s Beaver Valley Unit 2 sale and leaseback financing. Cash collateralized letters of credit associated with that financing were cancelled and replaced by unsecured LOCs totaling approximately $237 million (as described above) during the second quarter of 2004.
In connection with the sale of the TEBSA project in Colombia in January 2004, FirstEnergy guaranteed the obligations of the operators of the project, up to a maximum of $6 million (subject to escalation) under the project’s
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operation and maintenance agreement for so long as such obligations exist. The purchaser of TEBSA agreed to indemnify FirstEnergy against any loss under this guarantee. Also in connection with the TEBSA project, FirstEnergy has provided the TEBSA project lenders with a $60 million LOC and a $400,000 LOC. The $60 million LOC was established as a substitute asset for FirstEnergy’s interest in its Midlands companies pursuant to an indemnity agreement in favor of the TEBSA project lenders. As of October 15, 2004, the value of the LOC decreased to $46 million. The balance will continue to decline annually and will be fully discharged and released in October 2010. The substitute LOC enabled FirstEnergy to sell its remaining 20.1% interest in Avon (parent of Midlands Electricity in the United Kingdom). The $400,000 LOC was established to secure the TEBSA project lenders in the event that liquidated shares of TEBSA were unable to be converted into U.S. currency. The $400,000 LOC will terminate upon the registration of certain of TEBSA’s stock with the Colombian Central Bank.
OFF-BALANCE SHEET ARRANGEMENTS
FirstEnergy has obligations that are not included on its Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.4 billion as of September 30, 2004.
CEI and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a “qualified special purpose entity” under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $199 million of off-balance sheet financing as of September 30, 2004.
FirstEnergy has equity ownership interests in various businesses that are accounted for using the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under contractual obligations above.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices.
Commodity Price Risk
FirstEnergy is exposed to market risk primarily due to fluctuating electricity, natural gas, coal, nuclear fuel and emission allowance prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. Most of FirstEnergy’s non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133.
The change in the fair value of commodity derivative contracts related to energy production during the third quarter and first nine months of 2004 is summarized in the following table:
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Increase (Decrease) in the Fair ValueOf Commodity Derivative Contracts
Derivatives included on the Consolidated Balance Sheet as of September 30, 2004 were as follows:
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:
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,
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2004. Based on derivative contracts held as of September 30, 2004, an adverse 10% change in commodity prices would decrease net income by approximately $2 million during the next twelve months.
Interest Rate Swap Agreements
FirstEnergy enters into fixed-to-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues – protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. As a result of the differences between fixed and variable debt rates, interest expense was $10 million lower in the third quarter of 2004, compared to being $5 million lower in the third quarter of 2003. As of September 30, 2004, the debt underlying the interest rate swaps had a weighted average fixed interest rate of 5.53%, which the swaps have effectively converted to a current weighted average variable interest rate of 3.02%.
Equity Price Risk
Included in nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $857 million and $779 million as of September 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $86 million reduction in fair value as of September 30, 2004.
CREDIT RISK
Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.
FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy manages the quality of its portfolio of energy contracts evidenced by a current weighted average risk rating for energy contract counterparties of “BBB” (S&P). As of September 30, 2004, the largest credit concentration with any counterparty relationship was 7% – that counterparty is currently rated investment grade.
OUTLOOK
State Regulatory Matters
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions that are reflected in the EUOCs’ respective state regulatory plans. Those provisions include:
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Regulatory assets are costs which the respective regulatory agencies have authorized for recovery (or to be requested for authorization in the case of ATSI) from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets are expected to continue to be recovered under the provisions of the respective transition and regulatory plans as discussed below. The regulatory assets of the individual companies are as follows:
Regulatory assets by source are as follows:
The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization plans. These regulatory assets totaling $556 million as of September 30, 2004 (OE — $205 million, CEI — $271 million, TE — $80 million) will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized in each period.
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On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting a review of various reliability practices. FirstEnergy’s response confirmed that its review was completed and that various enhancements were underway to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts, a portion of which were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. FirstEnergy’s detailed implementation plan was endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives recommended by NERC were certified as complete by June 30, 2004, with one minor exception related to reactive testing of certain generators expected to be completed later this year.
On April 5, 2004, the U.S. – Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outages. The Final Report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force recommendations that were directed toward FirstEnergy and reported completion of those activities on June 30, 2004.
On April 22, 2004, FirstEnergy filed with the FERC the results of the FERC-ordered independent study of part of Ohio’s power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summers 2004 and 2009. Certain requested additional clarifications were provided to the FERC in October 2004. FirstEnergy completed the implementation of recommendations relating to 2004 by June 30, 2004, and is continuing to review results related to 2009. The estimated capital expenditures required by 2009 are not expected to have a material adverse effect on FirstEnergy’s financial results. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures.
In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and required additional reporting on reliability. The PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order approving the revised reliability benchmark and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. The Order permitted Pennsylvania utilities to file in a separate proceeding to revise the recomputed benchmarks and standards if they have evidence, such as the impact of automated outage management systems, on the accuracy of the PPUC computed reliability indices. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, seeking amendment of the benchmarks and standards due to their implementation of automated outage management systems following restructuring. No procedural schedule or hearing date has been set for this proceeding. FirstEnergy is unable to predict the outcome of this proceeding.
On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed’s, Penelec’s and Penn’s “service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring” in Pennsylvania. Hearings were held in early August 2004. On September 30, 2004, Met-Ed, Penelec and Penn filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the
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settlement, Met-Ed, Penelec and Penn agreed to enhance service reliability, performance reporting and communications with customers and to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. In November 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.
FirstEnergy’s transition plan for the Ohio Companies included approval for recovery of transition costs, including regulatory assets, through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement; granting preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators, to 1,120 MW of generation capacity through 2005 at established prices for sales to the Ohio Companies retail customers; and freezing customer prices through a five-year market development period (2001-2005), except for certain limited statutory exceptions including a 5% reduction in the price of generation for residential customers.
The Ohio Companies 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 through an extension of the regulatory transition charge.
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On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. The Ohio Companies retains the right to withdraw the modified Rate Stabilization Plan should subsequent adverse action be taken by the PUCO or a court. In the second quarter of 2004, the Ohio Companies implemented the accounting modifications contained in the PUCO’s June 9, 2004 Order, which are consistent with the PUCO’s August 4, 2004 Entry on Rehearing. Those modifications included amortization of transition costs based on extended amortization periods (that are no later than 2007 for OE, mid-2009 for CEI and mid-2008 for TE) and the deferral of interest costs on the accumulated deferred shopping incentives. On October 1, 2004, the OCC filed an appeal with the Ohio Supreme Court to overturn the June 9, 2004 PUCO order.
Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L’s two August 2002 rate filings requested increases in base electric rates of approximately $98 million annually and requested the recovery of deferred energy costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision, which reduced JCP&L’s annual revenues by approximately $62 million effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L’s rate base for the subsequent six to twelve months. During that period, the decision also required that, within approximately one year of its issuance, JCP&L would initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that Phase II proceeding, the NJBPU could increase JCP&L’s return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L’s service. Any reduction would be retroactive to August 1, 2003. The net revenue decrease from the NJBPU’s decision consists of a $223 million decrease in the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC. The decision in the deferred balances proceeding disallowed $153 million of deferred energy costs, so that the MTC allows for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis. As a result, JCP&L
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recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and $32 million of other disallowed regulatory assets. JCP&L filed an interim 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. In its final decision and order issued on May 17, 2004, the NJPBU clarified the method for calculating interest attributable to the cost disallowances, resulting in a $5.4 million reduction from the amount estimated in 2003. On June 1, 2004, JCP&L filed with the NJBPU a supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances, (2) the capital structure including the rate of return, (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning. All other issues included in JCP&L’s amended motion were denied. Oral arguments were held on August 4, 2004. Management is unable to predict when a decision may be reached by the NJBPU.
On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey shore. The NJBPU instituted an investigation into these outages, and directed that a Special Reliability Master (SRM) be hired to oversee the investigation. On December 8, 2003, the SRM issued his Interim Report recommending that JCP&L implement a series of actions to improve reliability in the area affected by the outages. The NJBPU adopted the findings and recommendations of the Interim Report on December 17, 2003, and ordered JCP&L to implement the recommended actions on a staggered basis, with initial actions to be completed by March 31, 2004. In late 2003, in accordance with a Settlement Stipulation concerning an August 2002 storm outage, the NJBPU engaged Booth & Associates to conduct an audit of the planning, operations and maintenance practices, policies and procedures of JCP&L. The audit was expanded to include the July 2003 outage and was completed in January 2004. On June 9, 2004, the NJBPU approved a stipulation that incorporated the final SRM report and portions of the final Booth report. The final order was issued by the NJBPU on July 23, 2004.
In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision also affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. FirstEnergy established reserves in 2002 for Met-Ed’s and Penelec’s PLR deferred energy costs which aggregated $287.1 million, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. FirstEnergy recorded in 2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to income for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million.
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On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Met-Ed’s and Penelec’s restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 20, 2001 order in its entirety. The PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day’s notice. In response to that order, Met-Ed and Penelec filed supplements to their tariffs to become effective October 24, 2003.
On October 8, 2003, Met-Ed and Penelec filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC’s findings would not impair their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed and Penelec for the NUG trust fund refund, denying Met-Ed’s and Penelec’s other clarification requests and granting ARIPPA’s petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC’s finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis.
On October 27, 2003, one Commonwealth Court judge issued an Order denying Met-Ed’s and Penelec’s Objection without explanation. Due to the vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed and Penelec, in order to preserve their rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC’s October 2 and October 16 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed’s and Penelec’s Objection was intended to be denied on the merits. In addition to these findings, Met-Ed and Penelec, in compliance with the PPUC’s Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC’s findings in their Orders.
Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy’s earnings and competitive position. These environmental regulations affect FirstEnergy’s earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be.
The EPA has proposed the Interstate Air Quality Rule to “cap-and-trade” NOx and SO2 emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO2 emissions would be reduced by approximately 3.6 million tons in 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities.
On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as “maximum achievable control
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technologies” (MACT) based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a “co-benefit” from implementation of SO2 and NOx emission caps under the EPA’s proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year. The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant which is owned by OE and Penn. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of “best available control technology” and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase trial to address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant has been rescheduled to January 2005 by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated in its August 2003 ruling that the remedies it “may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act.” The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy’s, OE’s and Penn’s respective financial condition and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of September 30, 2004.
In December 1997, delegates to the United Nations’ climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the U.S. Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity – the ratio of emissions to economic output – by 18% through 2012. The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2emissions could require significant capital and other expenditures. However, the CO2 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies’ diversified generation sources which includes low or non-CO2 emitting gas-fired and nuclear generators.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, and strict products liability. In November 2003, the trial court granted JCP&L’s motion to decertify the class and denied plaintiffs’ motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage
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rulings were appealed to the Appellate Division. The Appellate Court issued a decision on July 8, 2004, affirming the decertification of the originally certified class but remanding for certification of a class limited to those customers directly impacted by the outages of transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Court. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of September 30, 2004.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages effected approximately 1.4 million customers in FirstEnergy’s service area. On April 5, 2004, the U.S. –Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid’s reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility’s system. The final report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 (see Reliability Initiatives above). FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of September 30, 2004 for any expenditures in excess of those actually incurred through that date.
FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse plant. FirstEnergy is unable to predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002. Further, a petition was filed with the NRC on March 29, 2004 by a group objecting to the NRC’s restart order of the Davis-Besse Nuclear Power Station. The Petition seeks, among other things, suspension of the Davis-Besse operating license. A June 2, 2004 ASLB denial of the petition was appealed to the NRC. FENOC and the NRC staff filed opposition briefs on June 24, 2004. If it were ultimately
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determined that FirstEnergy or its subsidiaries has legal liability or is otherwise made subject to enforcement action based on the Davis-Besse outage, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition and results of operations.
On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC’s Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies and the Davis-Besse extended outage has become the subject of a formal order of investigation. The SEC’s formal order of investigation also encompasses issues raised during the SEC’s examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability or is otherwise made subject to liability based on any of the above matters, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition and results of operations.
CRITICAL ACCOUNTING POLICIES
FirstEnergy prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of FirstEnergy’s assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. FirstEnergy’s more significant accounting policies are described below.
Regulatory Accounting
FirstEnergy’s regulated services segment is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine FirstEnergy is permitted to recover. At
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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. 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.
Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management’s intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management’s expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. FirstEnergy continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, FirstEnergy enters into a significant number of commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments.
Revenue Recognition
FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, weather-related impacts and electricity provided by alternative suppliers.
Pension and Other Postretirement Benefits Accounting
FirstEnergy’s reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy’s merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.
In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants’ experience.
In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. FirstEnergy reduced its assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy’s pension costs in 2003 and in the first nine months of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan. This contribution will mitigate future
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funding requirements and significantly reduce the year-end minimum pension liability that currently reduces accumulated other comprehensive income by $300 million.
Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates.
Ohio Transition Cost Amortization
In connection with FirstEnergy’s initial transition plan, the PUCO determined allowable transition costs based on amounts recorded on the regulatory books of the Ohio electric utilities. These costs exceeded those deferred or capitalized on FirstEnergy’s balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). FirstEnergy uses an effective interest method for amortizing its transition costs, often referred to as a “mortgage-style” amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the Rate Stabilization Plan for each respective company. In computing the transition cost amortization, FirstEnergy includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off-balance sheet costs and the return associated with these costs are recognized as income when received.
Long-Lived Assets
In accordance with SFAS 144, FirstEnergy periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, FirstEnergy recognizes a loss – calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows).
The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment.
Nuclear Decommissioning
In accordance with SFAS 143, FirstEnergy recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of FirstEnergy’s current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants’ current license and settlement based on an extended license term.
In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is indicated, FirstEnergy recognizes a loss – calculated as the difference between the implied fair value of a reporting unit’s goodwill and the carrying value of the goodwill. FirstEnergy’s annual review of goodwill was completed in the third quarter of 2004, with no impairment indicated. 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. In the first nine months of 2004, FirstEnergy reduced goodwill by $27 million for pre-merger interest received on an income tax refund and other tax benefits. As of September 30, 2004, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment.
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NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
Exposure Draft of Proposed Statement of Financial Accounting Standards –Share-Based Payment – an amendment of FASB Statements No. 123 and 95
In March 2004, the FASB issued an exposure draft of a new standard, which would amend SFAS 123 and SFAS 95. Among other items, the new standard would require expensing stock options in FirstEnergy’s financial statements. In October 2004, the FASB agreed to delay the effective date of the proposed standard from January 1, 2005 to periods beginning after June 15, 2005, for calendar year companies. FirstEnergy will not be able to determine the impact of the proposed standard on its results of operations until the standard is issued in final form. The impact of the fair value recognition provisions of SFAS 123 on FirstEnergy’s net income and earnings per share for the current reporting periods is disclosed in Note 2.
Exposure Draft of Proposed Statement of Financial Accounting Standards –Earnings per Share – an amendment of FASB Statement No. 128
EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary and Its Application to Certain Investments”
EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies”
FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”
FIN 46 (revised December 2003), “Consolidation of Variable Interest Entities”
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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME(Unaudited)
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.
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The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.
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CONSOLIDATED STATEMENTS OF CASH FLOWS(Unaudited)
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board ofDirectors of Ohio Edison Company:
We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of September 30, 2004, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(F) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
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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. The OE Companies also provide generation services to those customers electing to retain the OE Companies as their power supplier. The OE Companies provide power directly to wholesale customers under previously negotiated contracts, as well as to some alternative energy suppliers under OE’s transition plan. The OE Companies have unbundled the price of electricity into its component elements – including generation, transmission, distribution and transition charges. Power supply requirements of the OE Companies are provided by FES — an affiliated company.
Results of Operations
Earnings on common stock in the third quarter of 2004 increased to $102 million from $80 million in the third quarter of 2003. For the first nine months of 2004, earnings on common stock increased to $264 million from $213 million in the same period of 2003. Earnings on common stock in the first nine months of 2003 included an after-tax credit of $32 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $183 million in the first nine months of 2003. Increased earnings in both 2004 periods resulted principally from lower nuclear operating costs and reduced interest charges — partially offset by higher purchased power costs compared to 2003. Lower nuclear operating costs in the third quarter and the first nine months of 2004, compared with the same periods of 2003, were due to the absence of nuclear refueling outages at the Beaver Valley Units and the Perry Plant in 2003. Lower net interest charges in the third quarter and the first nine months of 2004, compared with the same periods of 2003, were primarily due to debt redemptions. Reduced provisions for depreciation and amortization in the third quarter of 2004 and higher operating revenues in the first nine months of 2004 also contributed to increased earnings for those respective periods.
Operating revenues decreased by $8 million or 1.1% in the third quarter of 2004 from the same period of 2003. Lower revenues primarily resulted from a $13 million decrease in retail electric revenues which was partially offset by a $6 million (3.5%) increase in wholesale sales (primarily to FES) due to increased available nuclear generation. The net decrease in retail electric revenues reflected lower distribution throughput revenues and increased shopping incentive credits (reflecting an increase in the shopping credit rate in Ohio) which was partially offset by a $3 million increase in retail generation revenues. Lower kilowatt-hour sales to residential customers resulting from cooler weather which reduced air conditioning loads were partially offset by the effect of a stronger economy in OE’s service area. A $4 million increase in retail generation revenues to the commercial sector reflected a 1.7 percentage points decrease in electric generation services provided by alternative suppliers as a percent of total sales deliveries in the OE Companies’ franchise areas. Revenues from sales to residential customers decreased by $2 million as the corresponding percentage for shopping increased by 0.9 percentage points in the third quarter of 2004. Generation revenues from industrial customers were relatively flat as the percentage of customers shopping did not change.
Operating revenues increased by $37 million (1.7%) in the first nine months of 2004 compared with the same period in 2003 primarily due to a $36 million increase in wholesale sales. Revenues from wholesale sales to FES (resulting from increased nuclear generation available for sale) increased by $48 million, and was partially offset by $11 million of lower revenues due to the expiration of a contract in July 2003. Increased retail generation revenues of $15 million in the first nine months of 2004 reflected the same trend in shopping for generation providers (an increase of 1.8 percentage points for residential customers and decreases of 0.6 and 1.8 percentage points for commercial and industrial customers, respectively). Commercial and industrial revenues increased due to higher kilowatt-hour sales and unit prices which were partially offset by lower kilowatt-hour sales to residential customers.
Revenues from distribution throughput decreased by $4 million in the third quarter of 2004, but increased $1 million in the first nine months of 2004 compared with the corresponding periods of 2003. Distribution deliveries to residential customers decreased 1.6% in the third quarter of 2004 due to weather conditions as discussed above. Revenues from distribution deliveries to residential customers decreased by $7 million in the third quarter and $4 million in the first nine months of 2004 compared to the same periods of 2003 principally reflecting lower unit prices. Higher unit prices and increased distribution deliveries to commercial customers, as a result of the improving economy, increased revenues. Lower unit prices were the primary factors in the decrease in revenues from industrial customers.
Under the Ohio transition plan, OE provides incentives to customers to encourage switching to alternative energy providers — $11 million of additional credits in the third quarter and $12 million of additional credits in the first nine months of 2004 compared with the corresponding periods of 2003. These revenue reductions are deferred for future recovery under OE’s transition plan and do not materially affect current period earnings.
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Changes in electric generation sales and distribution deliveries in the third quarter and first nine months of 2004 from the corresponding periods of 2003 are summarized in the following table:
Operating Expenses and Taxes
Total operating expenses and taxes decreased $15 million in the third quarter and $5 million in the first nine months of 2004 from the same periods last year. The following table presents changes from the prior year by expense category.
Higher fuel costs in the third quarter and first nine months of 2004, compared with the same periods of 2003, resulted from increased nuclear generation – up 8.7% and 23.7%, respectively. Purchased power costs were higher in both periods of 2004 reflecting higher unit costs and increased kilowatt-hour purchases from nonaffiliated wholesale customers. Lower nuclear operating costs for both periods were due to the absence of refueling outages in 2004 – refueling outages were performed at Beaver Valley Unit 1 (100% interest), Perry plant (35.24% interest) and Beaver Valley Unit 2 (55.62% interest) in the first, second and third quarters of 2003, respectively. The decrease in other operating costs in the third quarter and first nine months of 2004, compared to the same periods of 2003, is due to reduced labor costs and lower employee benefits expenses.
Depreciation and amortization decreased in the third quarter of 2004 compared to the same period of 2003 primarily due to higher shopping incentive deferrals ($11 million) and deferred interest on the shopping incentives (see Regulatory Matters) in the third quarter of 2004 ($3 million). The increase in depreciation and amortization in the first nine months of 2004, compared with the first nine months of 2003 was primarily due to the increased amortization of Ohio transition regulatory assets ($18 million), lower tax-related deferrals ($4 million), offset by higher shopping incentive deferrals ($12 million) and deferred interest on shopping incentives ($7 million).
General taxes decreased in the first nine months of 2004 from the same period of 2003, primarily due to a $6 million refund received on a real estate valuation settlement.
Net Interest Charges
Net interest charges continued to trend lower, decreasing by $14 million in the third quarter and $36 million in the first nine months of 2004 from the same periods last year, reflecting redemptions and refinancings since the end of the third quarter of 2003. OE’s long-term debt redemptions (excluding revolving credit facility activity) totaled $105 million during the first nine months of 2004, which is expected to result in annualized savings of approximately $8 million.
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Upon adoption of SFAS 143 in the first quarter of 2003, OE recorded an after-tax credit to net income of $32 million. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $54 million increase to income, or $32 million net of income taxes.
Capital Resources and Liquidity
OE’s cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next two 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.
As of September 30, 2004, OE had $1 million of cash and cash equivalents, compared with $2 million as of December 31, 2003. The major sources of changes in these balances are summarized below.
Cash provided from operating activities during the third quarter and first nine months of 2004, compared with the corresponding periods in 2003, were as follows:
Net cash from operating activities decreased $345 million in the third quarter of 2004 from the third quarter of 2003 due to a $291 million decrease from changes in working capital and a voluntary pension trust contribution of $73 million. These decreases were partially offset in part by a $19 million increase in cash earnings as described above under “Results from Operations”. The change in working capital primarily reflects an increase in accounts receivable from associated companies and a decrease in accrued tax due to higher estimated tax payments in the third quarter of 2004 compared with the third quarter of 2003. These changes were partially offset by an increase in accounts payable. Net cash from operating activities decreased $538 million in the first nine months of 2004 due to a $583 million decrease from changes in working capital and the $73 million pension contribution. These decreases were partially offset by a $118 million increase in cash earnings. The change in working capital primarily reflects lower accounts payable and accrued taxes, reflecting changes of $249 million for the reallocation of tax liabilities between associated companies related to the tax sharing agreement.
In the third quarter of 2004, net cash used for financing activities was $14 million compared to $308 million in the third quarter of 2003. The change resulted from a $173 million decrease in net debt redemptions, a $96 million net increase in short-term borrowings and a $26 million decrease in common stock dividend payments to FirstEnergy. In the first nine months of 2004, net cash used for financing activities decreased to $350 million from $496 million in the same period last year. The decrease resulted from reduced payments on short-term borrowings of $236 million and $140 million of reduced common stock dividends to FirstEnergy, partially offset by $230 million of reduced financings in 2004.
On June 7, 2004, OE replaced certain collateralized LOCs that were issued in 1994 in support of OE’s obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. Approximately $289 million in cash collateral and accrued interest previously held by OES Finance Incorporated, a wholly owned subsidiary of OE, was released on July 15, 2004 upon cancellation of the existing LOCs and was used to repay short-term debt and for other corporate purposes. Simultaneously with the issuance of the replacement LOCs, OE entered into a Credit Agreement pursuant to which a standby LOC was issued in support of the replacement LOCs, and the issuer of the LOCs obtained
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the right to pledge or assign participations in OE’s reimbursement obligations to a trust. The trust then issued and sold trust certificates to institutional investors that were designed to be the credit equivalent of an investment directly in OE.
OE had approximately $637 million of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $196 million of short-term indebtedness as of September 30, 2004. Available borrowing capability under bilateral bank facilities totaled $14 million as of September 30, 2004. OE has obtained authorization from the PUCO to incur short-term debt of up to $500 million (including bank facilities and the utility money pool described below). Penn has obtained authorization from the SEC to incur short-term debt up to its charter limit of $46 million (including the utility money pool). OE and Penn had the capability to issue $1.6 billion and $497 million, respectively, of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE is subject to a provision of its senior note indenture generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, this provision would permit OE to incur additional secured debt not otherwise permitted by a specified exception of up to $639 million as of September 30, 2004. Based upon applicable earnings coverage tests, the OE Companies could issue up to $3.1 billion of preferred stock (assuming no additional debt was issued) as of September 30, 2004.
OE’s $125 million 364-day revolving credit facility was restructured through a new syndicated FirstEnergy facility that was completed on June 22, 2004. Combined with an existing syndicated $125 million three-year facility for OE maturing in October 2006, an existing syndicated $250 million two-year facility for OE maturing in May 2005 and bank facilities of $34 million, OE’s credit facilities total $409 million, of which $389 million was unused as of September 30, 2004. These facilities are intended to provide liquidity to meet the short-term working capital requirements of OE and its regulated affiliates.
Borrowings under these facilities are conditioned on OE maintaining compliance with certain financial covenants. OE, under its $125 million 364-day and $250 million two-year facilities, is required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually-defined fixed charge coverage ratio of no less than 2 to 1. OE is in compliance with these financial covenants. As of September 30, 2004, OE’s fixed charge coverage ratio, as defined under the credit agreements, was 7.36 to 1. OE’s debt to total capitalization ratio, as defined under the credit agreements, was 0.39 to 1. The ability to draw on these facilities is also conditioned upon OE making certain representations and warranties to the lending banks prior to drawing on its facilities, including a representation that there has been no material adverse change in its business, its condition (financial or otherwise), its results of operations, or its prospects.
OE’s primary credit facilities contain no provisions restricting its ability to borrow, or accelerating repayment of outstanding loans, as a result of any change in its S&P or Moody’s credit ratings. The primary facilities do contain “pricing grids”, whereby the cost of funds borrowed under the facilities is related to the credit ratings of the company borrowing the funds.
OE has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Available bank borrowings include $1.75 billion from FirstEnergy’s and OE’s revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2004 was 1.28%.
In March 2004, Penn completed a receivables financing arrangement that provides borrowing capability of up to $25 million. The borrowing rate is based on bank commercial paper rates. Penn is required to pay an annual facility fee of 0.40% on the entire finance limit. The facility was undrawn as of September 30, 2004 and matures on March 29, 2005.
OE’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook on all such securities is stable.
On July 22, 2004, S&P updated its analysis of U.S. utility FMBs in response to changes in the industry. As a result of its revised methodology for evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility companies, including Penn. Penn’s FMB credit rating was upgraded to BBB from BBB-.
On August 26, 2004, S&P stated that a favorable outcome of the Ohio Rate Stabilization Plan auction process and a favorable resolution of pending environmental litigation would support a higher ratings outlook, or possibly a higher rating. S&P noted that a ratings upgrade in 2004 does not appear likely because those major issues would most likely not be resolved before the end of 2004. On September 14, 2004, S&P stated that FirstEnergy’s $500 million voluntary contribution to its pension plan was credit neutral.
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Net cash used for investing activities totaled $190 million in the third quarter of 2004 and $134 million provided from investing activities for the first nine months of 2004, compared to net cash used for investing activities of $241 million and $275 million, respectively, for the same periods of 2003. The $51 million change for the third quarter and $409 million for the first nine months, resulted primarily from $278 million of cash proceeds from certificates of deposit in the third quarter of 2004. Loans to associated companies increased $181 million in the third quarter of 2004 and decreased $177 million first nine months, compared to the same periods in 2003.
During the last quarter of 2004, capital requirements for property additions and capital leases are expected to be about $78 million, including $29 million for nuclear fuel. OE has additional requirements of approximately $18 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. Those requirements are expected to be satisfied from internal cash and short-term credit arrangements.
Off-Balance Sheet Arrangements
Obligations not included on OE’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. As of September 30, 2004, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $696 million.
Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $227 million and $209 million as of September 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $23 million reduction in fair value as of September 30, 2004.
Outlook
Beginning in 2001, OE’s customers were able to select alternative energy suppliers. OE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
Regulatory Matters
Beginning on January 1, 2001, OE’s customers were able to choose their electricity suppliers. Customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE’s customers elects to obtain power from an alternative supplier, OE reduces the customer’s bill with a “generation shopping credit,” based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. Under the recently approved Rate Stabilization Plan, OE has continuing PLR responsibility to its franchise customers through December 31, 2008.
As part of OE’s transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. OE is also required to provide 560 MW of low cost supply to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in OE’s franchise area.
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Under that proposal, OE requested:
On February 23, 2004, after consideration of the PUCO Staff comments and testimony as well as those provided by some of the intervening parties, OE made certain modifications to the Rate Stabilization Plan. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process on or before December 1, 2004. In addition to requiring the competitive bid process, the PUCO made other modifications to OE’s revised Rate Stabilization Plan application. Among the major modifications were the following:
On June 18, 2004, OE filed with the PUCO an application for rehearing of the modified version of the Rate Stabilization Plan. Several other parties also filed applications for rehearing. On August 4, 2004, the PUCO issued an Entry on Rehearing modifying its June 9, 2004 Order. The modifications included the following:
On August 5, 2004, OE accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. OE retains the right to withdraw the modified Rate Stabilization Plan should subsequent adverse action be taken by the PUCO or a court. In the second quarter of 2004, OE implemented the accounting modifications contained in the PUCO’s June 9, 2004 Order, which are consistent with the PUCO’s August 4, 2004 Entry on Rehearing. Those modifications included amortization of transition costs based on extended amortization periods (that are no later than 2007 for OE) and the deferral of interest costs on the accumulated deferred shopping incentives. On October 1, 2004, the OCC filed an appeal with the Ohio Supreme Court to overturn the June 9, 2004 PUCO order.
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OE filed a proposed competitive bid process which the PUCO modified on October 6, 2004. The PUCO approved the rules for the competitive bid process setting a three-year supply period (2006-2008) requirement for generation service suppliers and a load cap for individual suppliers. In mid-October, the initial auction schedule was revised so that Part 1 and Part 2 auction bidder applications are due November 4 and November 15, 2004, respectively; the trial auction is scheduled to occur on December 3; the auction would commence December 8 and the PUCO will accept or reject the auction results within two business days after the completion of the auction. FirstEnergy has elected not to participate in the auction.
Regulatory Assets
Regulatory assets are costs which have been authorized by the PUCO, PPUC and the FERC, for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. The OE Companies’ regulatory assets are expected to continue to be recovered under the provisions of their respective transition plan and rate restructuring plans. The OE Companies’ regulatory assets were as follows:
On February 26 and 27, 2004, OE, as part of a NERC review of control area operations throughout the United States, participated in a NERC Control Area Readiness Audit. The final audit report, completed on May 6, 2004, identified positive observations and included various recommendations for reliability improvement. FirstEnergy reported completion of those recommendations on June 30, 2004, with one exception related to MISO’s implementation of a voltage stability tool expected to be completed later this year.
On March 1, 2004, OE filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. – Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy’s control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding.
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In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and required additional reporting on reliability. The PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order approving the revised reliability benchmark and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. The Order permitted Pennsylvania utilities to file in a separate proceeding to revise the recomputed benchmarks and standards if they have evidence, such as the impact of automated outage management systems, on the accuracy of the PPUC computed reliability indices. Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards due to their implementation of automated outage management systems following restructuring. No procedural schedule or hearing date has been set for this proceeding. Penn is unable to predict the outcome of this proceeding.
On January 16, 2004, the PPUC initiated a formal investigation of whether Penn’s “service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring” in Pennsylvania. Hearings were held in early August 2004. On September 30, 2004, Penn filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settlement, Penn agreed to enhance service reliability, performance reporting and communications with customers and together with Met-Ed and Penelec, to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. In November 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.
Various federal, state and local authorities regulate OE with regard to air and water quality and other environmental matters. The effects of compliance on OE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect OE’s earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, OE believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be.
OE is required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. OE cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
In 1999 and 2000, the EPA issued NOV or a Compliance Orders 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. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of “best available control technology” and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase trial to address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant has been rescheduled to January 2005 by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, 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
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required, could have a material adverse impact on the OE Companies’ financial condition and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of September 30, 2004.
The OE Companies believe they are complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the OE Companies’ facilities. The EPA’s NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. SIPs were required to comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the state NOx budgets at the OE Companies’ Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires required compliance with the state NOx budgets at the OE Companies’ Ohio facilities by May 31, 2004. The OE Companies believe their facilities are complying with the state NOx budgets through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.
On September 7, 2004, the EPA established new performance standards under Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are drawn into a facility’s cooling water system. The OE Companies are conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance standards. The OE Companies are unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may be substantial.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy’s service area. On April 5, 2004, the U.S. –Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid’s reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility’s system. The final report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 (see Reliability initiatives above). FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of September 30, 2004 for any expenditures in excess of those actually incurred through that date.
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Legal Matters
Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to OE’s normal business operations are pending against OE and its subsidiaries. The most significant not otherwise discussed above are described below.
On August 12, 2004, the NRC publicly disclosed that it was notifying FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. The OE Companies have a 35.24% interest in the Perry Nuclear Power Plant. The NRC noted that the plant continues to operate safely. The increased oversight will include an extensive NRC team inspection to access the equipment problems and FirstEnergy’s corrective actions. The outcome of this increased oversight is not known at this time.
On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC’s Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and OE and the Davis-Besse extended outage (OE has no interest in Davis-Besse) has become the subject of a formal order of investigation. The SEC’s formal order of investigation also encompasses issues raised during the SEC’s examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
Critical Accounting Policies
OE prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of the OE Companies’ assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. The OE Companies’ more significant accounting policies are described below.
The OE Companies are subject to regulation that sets the prices (rates) they are permitted to charge their customers based on costs that the regulatory agencies determine the OE Companies are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. 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.
The OE Companies follow the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, weather-related impacts and electricity provided by alternative suppliers.
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FirstEnergy’s pension and postretirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. OE’s reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy’s merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy’s pension costs in 2003 and in the first nine months of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan ($73 million funded by the OE Companies). This contribution will mitigate future funding requirements and significantly reduce the year-end minimum pension liability that currently reduces the OE Companies’ accumulated other comprehensive income by $62 million.
In connection with FirstEnergy’s initial transition plan, the PUCO determined allowable transition costs based on amounts recorded on OE’s regulatory books. These costs exceeded those deferred or capitalized on OE’s balance sheet prepared under GAAP since they included certain costs which have not yet been incurred. OE uses an effective interest method for amortizing its transition costs, often referred to as a “mortgage-style” amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the Rate Stabilization 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.
In accordance with SFAS 144, the OE Companies periodically evaluate their long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, the OE Companies recognize a loss – calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows).
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In accordance with SFAS 143, the OE Companies recognize an ARO for the future decommissioning of their nuclear power plants. The ARO represents an estimate of the fair value of the OE Companies’ current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. The OE Companies used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants’ current license and settlement based on an extended license term.
New Accounting Standards And Interpretations
In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, OE will continue to evaluate its investments as required by existing authoritative guidance.
Issued in May 2004, FSP 106-2 provides guidance on the accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. See Note 4 for a discussion of the effect of the federal subsidy provided under the Medicare Act on the consolidated financial statements.
In December 2003, the FASB issued a revised interpretation of ARB 51, referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, OE adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on OE’s consolidated financial statements. See Note 2 – Consolidation for a discussion of variable interest entities.
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.
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The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these balance sheets.
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To the Stockholders and Board ofDirectors of The ClevelandElectric Illuminating Company:
We have reviewed the accompanying consolidated balance sheet of The Cleveland Illuminating Electric Company and its subsidiaries as of September 30, 2004, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(F) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
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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 CEI 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.
Earnings on common stock in the third quarter of 2004 increased to $81 million from $66 million in the third quarter of 2003. For the first nine months of 2004, earnings on common stock increased to $175 million from $132 million in the same period of 2003. Earnings on common stock in the first nine months of 2003 included an after-tax credit of $42 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $92 million in the first nine months of 2003. Increased earnings in both 2004 periods resulted principally from higher operating revenues, lower nuclear operating costs and reduced interest charges — partially offset by higher fuel and other operating costs compared to 2003. Revenues for both periods were higher due to significant increases in sales to FES. Lower nuclear operating costs in the third quarter and the first nine months of 2004, compared with the same periods of 2003, were due to reduced incremental maintenance costs associated with the Davis-Besse extended outage and the absence of nuclear refueling outages at Beaver Valley Unit 2 and the Perry Plant in 2003. Lower net interest charges in the third quarter and the first nine months of 2004, compared with the same periods of 2003, were primarily due to debt redemptions and refinancing activities.
Operating revenues increased by $9 million or 1.8% in the third quarter from the same period of 2003. Higher revenues resulted principally from a $39 million (49.5%) increase in wholesale sales (primarily to FES) due to increased nuclear generation available for sale which was partially offset by reduced generation sales revenue from franchise customers of $8 million. The reduction in retail generation revenues (residential — $4 million and commercial — $2 million) in the third quarter of 2004 reflected increases in electric generation services to residential and commercial customers provided by alternative suppliers as a percent of total sales deliveries in CEI’s franchise area of 4.6 percentage points and 7.6 percentage points, respectively while the corresponding percentage for industrial customers decreased by 4.3 percentage points. Lower industrial sales unit prices offset the impact of an increase in kilowatt-hour sales to industrial customers. In the first nine months of 2004, operating revenues increased by $44 million (3.3%) primarily as a result of a $96 million increase in wholesale revenues (primarily to FES) due to increased available nuclear generation in the first nine months of 2004. The increase in wholesale revenues was partially offset by a 2.8% decrease in retail generation sales, which resulted in lower revenues of $19 million. Decreased retail generation revenues in the first nine months of 2004 reflected the same trend in shopping for generation providers (increases of 7.4 and 9.1 percentage points for residential and commercial customers, respectively, and a decrease of 3.7 percentage points for industrial customers). Residential and commercial revenues decreased due to lower kilowatt-hour sales and unit prices that were partially offset by an increase in revenue from higher industrial generation sales. The higher industrial revenues resulted from increased sales that were partially offset by lower unit prices.
Revenues from distribution throughput decreased by $22 million and $27 million in the third quarter and first nine months of 2004, respectively, as compared to the same periods of 2003, even though total distribution deliveries were nearly unchanged in the third quarter and increased 0.7% in the first nine months of 2004. Distribution deliveries to residential customers decreased 8.0% in the third quarter and 3.7% in the first nine months of 2004 resulting from cooler weather in the third quarter of 2004 as compared to the same quarter of 2003 which reduced air conditioning loads. An improving economy increased distribution deliveries to commercial and industrial customers in the third quarter and first nine months of 2004. Lower unit prices in all customer sectors for both periods offset the effect of higher distribution deliveries to commercial and industrial customers.
Under the Ohio transition plan, CEI provides incentives to customers to encourage switching to alternative energy providers – $2 million of additional credits in the third quarter and $6 million of additional credits in the first nine months of 2004 compared with the corresponding periods of 2003. These revenue reductions are deferred for future recovery under the transition plan and do not materially affect current period earnings.
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Total operating expenses and taxes increased by $7 million in the third quarter of 2004 from the third quarter of 2003 and decreased by $10 million in the first nine months of 2004 from the first nine months of 2003. The following table presents changes from the prior year by expense category.
Higher fuel costs in the third quarter and first nine months of 2004, compared with the same periods of 2003, resulted principally from the increased nuclear generation. Higher purchased power costs in the first nine months of 2004 compared with the same time period of 2003 reflect higher unit costs, partially offset by lower kilowatt-hours purchased. The decrease in nuclear operating costs for both periods were due to reduced incremental costs associated with the Davis-Besse extended outage and work performed during the Perry plant 56-day refueling outage (44.85% ownership) in the second quarter of 2003 and the Beaver Valley Unit 2 refueling outage (24.47% ownership) in the third quarter of 2003. Other operating costs increased in the third quarter and first nine months of 2004, compared to the same periods of 2003, in part from higher employee benefit costs.
The increase in depreciation and amortization charges in the third quarter of 2004, compared with the third quarter of 2003, was primarily due to higher amortization of regulatory assets ($10 million), partially offset by higher shopping incentive deferrals ($2 million) and deferred interest on the shopping incentives (see Regulatory Matters) in the third quarter of 2004 ($4 million). The increase in depreciation and amortization charges in the first nine months of 2004, compared with the first nine months of 2003 was primarily due to increased amortization of regulatory assets ($26 million), partially offset by higher shopping incentive deferrals ($6 million) and deferred interest on the shopping incentives ($12 million).
General taxes decreased in the first nine months of 2004, compared to the same period last year, reflecting in part a $2 million refund received on a real estate valuation settlement.
Other Income
Other income increased by $2 million in the third quarter and $14 million in the first nine months of 2004, compared to the same period in 2003, principally due to interest income from Shippingport which was consolidated into CEI as of December 31, 2003.
Net interest charges continued to trend lower, decreasing by $10 million in the third quarter and $20 million in the first nine months of 2004 from the same periods last year, reflecting redemptions and refinancings since the end of the third quarter of 2003. CEI’s long-term debt redemptions of $289 million during the first nine months of 2004 are expected to result in annualized savings of approximately $26 million.
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Upon adoption of SFAS 143 in the first quarter of 2003, CEI recorded an after-tax credit to net income of $42 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $73 million increase to income, or $42 million net of income taxes.
Preferred Stock Dividend Requirements
Preferred stock dividend requirements increased $2 million in the first nine months of 2004, compared to the same period last year, due to an adjustment that reduced costs in the first quarter of 2003.
CEI’s cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next two 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.
As of September 30, 2004, CEI had $200,000 of cash and cash equivalents, compared with $25 million as of December 31, 2003. The major sources of changes in these balances are summarized below.
Cash provided by operating activities during the third quarter and first nine months of 2004, compared with the corresponding periods in 2003, were as follows:
Net cash provided from operating activities increased $6 million in the third quarter of 2004 from the third quarter of 2003 as a result of a $26 million increase in cash earnings as described above under “Results of Operations” and an $12 million increase from changes in working capital, partially offset by a voluntary pension trust contribution of $32 million. The largest factor contributing to the increase in working capital was an increase in accounts payable partially offset by a decrease in receivables. Net cash provided from operating activities, increased $38 million in the first nine months of 2004 compared to the same period last year as a result of a $133 million increase in cash earnings, partially offset by a $63 million reduction from changes in working capital and the $32 million pension contribution. The change in working capital was principally due to a decrease in accrued taxes partially offset by an increase in accounts payable. The increase in cash earnings reflects the favorable impact of reduced nuclear operating costs and lower interest charges in 2004.
Net cash used for financing activities decreased by $55 million in the third quarter of 2004 from the third quarter of 2003. The decrease in funds used for financing activities resulted from an increase in short-term borrowings in 2004 to finance a portion of debt redemptions. Net cash used for financing activities increased $2 million in the first nine months of 2004 from the same period last year. The increase resulted from a $145 million increase in common stock dividends to FirstEnergy, nearly offset by a $143 million reduction in net debt redemptions.
CEI had about $0.8 million of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $331 million of short-term indebtedness as of September 30, 2004. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million (including the utility money pool
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described below). CEI had the capability to issue $1.4 billion of additional first mortgage bonds on the basis of property additions and retired bonds under the terms of its mortgage indenture. The issuance of FMB by CEI is subject to a provision of its senior note indenture generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, this provision would permit CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $582 million as of September 30, 2004. CEI has no restrictions on the issuance of preferred stock.
CEI has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2004 was 1.28%.
On September 2, 2004 and October 1, 2004, Ohio Water Development Authority pollution control notes aggregating $46.1 million and $23.3 million, respectively, were refunded. The new notes were issued in a Dutch Auction interest rate mode, insured by a municipal bond insurance policy and secured by FMBs.
CEI’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook on all such securities is stable.
In the third quarter and first nine months of 2004, net cash used for investing activities increased $61 million and $30 million, respectively, from the corresponding periods of 2003. The increase in cash used for investing activities primarily reflected increases in net cash used for investments in lessor notes.
During the fourth quarter of 2004, capital requirements for property additions are expected to be about $59 million, including $30 million for nuclear fuel. CEI has no sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004.
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, 2004, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $113 million.
CEI sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a “qualified special purpose entity” under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $131 million of off-balance sheet financing as of September 30, 2004.
As of September 30, 2004, off-balance sheet arrangements include certain statutory business trusts created by CEI to issue trust preferred securities in the amount of $100 million. These trusts were included in the consolidated financial statements of FirstEnergy prior to adoption of FIN 46R effective December 31, 2003, but have subsequently been deconsolidated under FIN 46R (see Note 2 – Consolidation). The deconsolidation under FIN 46R did not result in any change in outstanding debt.
Included in CEI’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $214 million and $188 million as of September 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $21 million reduction in fair value as of September 30, 2004.
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Beginning in 2001, CEI’s customers were able to select alternative energy suppliers. CEI continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates were restructured into separate components to support customer choice. CEI has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.
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. Under the recently approved Rate Stabilization Plan, CEI has continuing PLR responsibility to its franchise customers through December 31, 2008.
As part of CEI’s transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. CEI is also required to provide 400 MW of low cost supply to unaffiliated alternative suppliers who serve customers within its service area. CEI’s competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area.
Under that proposal, CEI requested:
On February 23, 2004, after consideration of the PUCO Staff comments and testimony as well as those provided by some of the intervening parties, CEI made certain modifications to the Rate Stabilization Plan. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process on or before December 1, 2004. In addition to requiring the competitive bid process, the PUCO made other modifications to CEI’s revised Rate Stabilization Plan application. Among the major modifications were the following:
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On June 18, 2004, CEI filed with the PUCO an application for rehearing of the modified version of the Rate Stabilization Plan. Several other parties also filed applications for rehearing. On August 4, 2004, the PUCO issued an Entry on Rehearing modifying its June 9, 2004 Order. The modifications included the following:
On August 5, 2004, CEI accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. CEI retains the right to withdraw the modified Rate Stabilization Plan should subsequent adverse action be taken by the PUCO or a court. In the second quarter of 2004, CEI implemented the accounting modifications contained in the PUCO’s June 9, 2004 Order, which are consistent with the PUCO’s August 4, 2004 Entry on Rehearing. Those modifications included amortization of transition costs based on extended amortization periods (that are no later than mid-2009 for CEI) and the deferral of interest costs on the accumulated deferred shopping incentives. On October 1, 2004, the OCC filed an appeal with the Ohio Supreme Court to overturn the June 9, 2004 PUCO order.
CEI filed a proposed competitive bid process which the PUCO modified on October 6, 2004. The PUCO approved the rules for the competitive bid process setting a three-year supply period (2006-2008) requirement for generation service suppliers and a load cap for individual suppliers. In mid-October, the initial auction schedule was revised so that Part 1 and Part 2 auction bidder applications are due November 4 and November 15, 2004, respectively; the trial auction is scheduled to occur on December 3; the auction would commence December 8 and the PUCO will accept or reject the auction results within two business days after the completion of the auction. FirstEnergy has elected not to participate in the auction.
Regulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. CEI’s regulatory assets as of September 30, 2004 and December 2003 were $1.0 billion and $1.1 billion, respectively.
On February 26 and 27, 2004, CEI, as part of a NERC review of control area operations throughout the United States, participated in a NERC Control Area Readiness Audit. The final audit report, completed on May 6, 2004, identified positive observations and included various recommendations for reliability improvement. FirstEnergy reported completion of those recommendations on June 30, 2004, with one exception related to MISO’s implementation of a voltage stability tool expected to be completed later this year.
On April 5, 2004, the U.S. – Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outages. The Final Report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one relates to
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activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force recommendations that were directed toward FirstEnergy and reported completion of those activities on June 30, 2004.
On March 1, 2004, CEI filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. – Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy’s control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding.
Various federal, state and local authorities regulate CEI with regard to air and water quality and other environmental matters. The effects of compliance on CEI with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect CEI’s earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, CEI believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be.
CEI is required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. CEI cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
CEI believes it is complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOxreductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from CEI’s Ohio and Pennsylvania facilities. The EPA’s NOxTransport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOxemissions are contributing significantly to ozone levels in the eastern United States. SIPs were required to comply by May 31, 2004 with individual state NOxbudgets. Pennsylvania submitted a SIP that required compliance with the state NOx budgets at CEI’s Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that required compliance with the state NOx budgets at CEI’s Ohio facilities by May 31, 2004. CEI believes its facilities are complying with the state NOx budgets through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.
CEI has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, CEI’s proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. CEI
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has accrued liabilities aggregating approximately $2.4 million as of September 30, 2004. CEI accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in CEI’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
On September 7, 2004, the EPA established new performance standards under Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are drawn into a facility’s cooling water system. CEI is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance standards. CEI is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may be substantial.
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Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to CEI’s normal business operations are pending against CEI and its subsidiaries. The most significant not otherwise discussed above are described below.
On August 12, 2004, the NRC publicly disclosed that it was notifying FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. CEI has a 44.85% interest in the Perry Nuclear Power Plant. The NRC noted that the plant continues to operate safely. The increased oversight will include an extensive NRC team inspection to access the equipment problems and FirstEnergy’s corrective actions. The outcome of this increased oversight is not known at this time.
On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC’s Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and CEI and the Davis-Besse extended outage has become the subject of a formal order of investigation. The SEC’s formal order of investigation also encompasses issues raised during the SEC’s examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
CEI prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of CEI’s assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. CEI’s more significant accounting policies are described below.
CEI is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine CEI is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. 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.
CEI follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end
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of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class, weather-related impacts and electricity provided by alternative suppliers.
FirstEnergy’s pension and postretirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. CEI’s reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy’s merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy’s pension costs in 2003 and in the first nine months of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution ($32 million funded by CEI) to its pension plan. This contribution will mitigate future funding requirements and significantly reduce the year-end minimum pension liability that currently reduces CEI’s accumulated other comprehensive income by $25 million.
In connection with FirstEnergy’s initial transition plan, the PUCO determined allowable transition costs based on amounts recorded on CEI’s regulatory books. These costs exceeded those deferred or capitalized on CEI’s balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). CEI uses an effective interest method for amortizing its transition costs, often referred to as a “mortgage-style” amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the Rate Stabilization 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.
In accordance with SFAS 144, CEI periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has
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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).
In accordance with SFAS 143, CEI recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of CEI’s current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. CEI used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants’ current license and settlement based on an extended license term.
In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, CEI evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were to be indicated, CEI would recognize a loss – calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. CEI’s most recent annual review was completed in the third quarter of 2004, with no impairment of goodwill indicated. The forecasts used in CEI’s evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on CEI’s future evaluations of goodwill. As of September 30, 2004, CEI had $1.7 billion of goodwill.
In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, CEI will continue to evaluate its investments as required by existing authoritative guidance.
In December 2003, the FASB issued a revised interpretation of ARB 51, referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, CEI adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. See Note 2 – Consolidation for a discussion of variable interest entities and the impact of the FIN 46 implementation on the financial statements of CEI.
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THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.
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CONSOLIDATED BALANCE SHEETS
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
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To the Stockholders and Board ofDirectors of The ToledoEdison Company:
We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of September 30, 2004, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.
As discussed in Note 2 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the three-month and nine-month periods ended September 30, 2003.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(F) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
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TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE provides power directly to some alternative energy suppliers under TE’s transition plan. TE has unbundled the price of electricity into its component elements – including generation, transmission, distribution and transition charges. Power supply requirements of TE are provided by FES – an affiliated company.
Restatements of Previously Reported Quarterly Results
As discussed in Note 2 to the Consolidated Financial Statements, TE’s quarterly results for the third quarter and first nine months of 2003 have been restated to correct the amounts reported for operating expenses and interest charges. TE’s costs which were originally recorded as operating expenses and should have been capitalized to construction were $1.1 million ($0.6 million after tax) and $2.1 million ($1.2 million after tax) in the third quarter and the first nine months of 2003, respectively. In addition, TE’s interest expense was overstated by $0.3 million ($0.2 million after tax) and $1.6 million ($1.0 million after tax) in the third quarter and the first nine months of 2003, respectively. The impact of these adjustments was not material to TE’s Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003.
Earnings on common stock in the third quarter of 2004 increased to $22 million from $14 million in the third quarter of 2003. For the first nine months of 2004, earnings on common stock increased to $47 million from $26 million in the same period of 2003. Earnings on common stock in the first nine months of 2003 included an after-tax credit of $26 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $7 million in the first nine months of 2003. Increased earnings in both 2004 periods resulted principally from higher operating revenues, lower nuclear operating costs and reduced interest charges — partially offset by higher fuel and other operating costs and provisions for depreciation and amortization. Revenues in both periods were higher due to significant increases in sales to FES. Lower nuclear operating costs in the third quarter and the first nine months of 2004, compared with the same periods of 2003, were due to reduced incremental maintenance costs associated with the Davis-Besse extended outage and the absence of nuclear refueling outages at Beaver Valley Unit 2 and the Perry Plant in 2003. Lower net interest charges in the third quarter and the first nine months of 2004, compared with the same periods of 2003, were primarily due to debt redemptions and refinancing activities.
Operating revenues increased by $16 million or 6.2% in the third quarter from the same period of 2003. Higher revenues resulted principally from a $25 million (38.9%) increase in wholesale sales (primarily to FES) due to increased nuclear generation available for sale with almost no change in total generation sales revenues from franchise customers. Reduced retail generation revenues (residential and commercial — $1 million each) in the third quarter of 2004 reflected increases in electric generation services to residential and commercial customers provided by alternative suppliers as a percent of total sales deliveries in TE’s franchise area of 5.6 percentage points and 1.7 percentage points, respectively, while shopping by industrial customers was unchanged. Increased industrial customer generation revenues of $3 million was due to higher unit prices offsetting a 2.3% decrease in kilowatt-hour sales. In the first nine months of 2004, operating revenues increased by $47 million or 6.7% primarily as a result of a $73 million increase in wholesale revenues (primarily to FES) due to increased available nuclear generation. The increase in wholesale revenues was partially offset by a 4.6% decrease in retail generation sales, which resulted in lower revenues of $8 million. Decreased retail generation revenues in the first nine months of 2004 reflected the same trend in shopping for generation providers (increases of 5.8 and 2.1 percentage points for residential and commercial customers, respectively, and a slight decrease of 0.4 percentage points for industrial customers). Retail revenues decreased due to lower kilowatt-hour sales in all customer sectors and lower unit prices in the residential and commercial sectors. Industrial revenues remained unchanged as lower kilowatt-hour sales were offset by higher unit prices.
Revenues from distribution throughput decreased by $7 million and $13 million in the third quarter and first nine months of 2004, respectively, as compared to the same periods of 2003, reflecting reduced usage and lower unit prices in all customer sectors. Distribution deliveries to commercial and industrial customers decreased and deliveries to residential customers were nearly unchanged in the third quarter of 2004 as compared to the same quarter of 2003. Total distribution deliveries decreased by 2.4% in the first nine months of 2004, compared to the same period in 2003. Weak economic conditions in TE’s franchise area contributed to lower distribution deliveries to commercial and industrial customers in the third quarter and first nine months of 2004. Lower unit prices in all customer sectors for both periods contributed to the decrease in revenues from electricity throughput.
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Under the Ohio transition plan, TE provides incentives to customers to encourage switching to alternative energy providers — $2 million of additional credits in the third quarter and $3 million of additional credits in the first nine months of 2004 compared with the corresponding periods of 2003. These revenue reductions are deferred for future recovery under TE’s transition plan and do not materially affect current period earnings.
Total operating expenses and taxes increased by $10 million in the third quarter and $7 million in the first nine months of 2004 from the same periods in 2003. The following table presents changes from the prior year by expense category.
Higher fuel costs in the third quarter and first nine months of 2004, compared with the same periods of 2003, resulted principally from increased nuclear generation. Purchased power costs increased in the first nine months of 2004, compared to the same period of 2003, due to higher unit costs, partially offset by lower kilowatt-hours purchased. The decreases in nuclear operating costs for both periods were due to reduced incremental costs associated with the Davis-Besse extended outage and work performed during the Perry plant 56-day refueling outage (19.91% interest) in the second quarter of 2003 and the Beaver Valley Unit 2 refueling outage (19.91% interest) in the third quarter of 2003. Other operating costs increased in the third quarter and first nine months of 2004, compared to the same periods of 2003, in part from higher vegetation management costs.
The increase in depreciation and amortization charges in the third quarter of 2004, compared with the third quarter of 2003, was primarily due to higher amortization of regulatory assets ($10 million), partially offset by higher shopping incentive deferrals ($2 million) and deferred interest on the shopping incentives (see Regulatory Matters) ($1 million). The increase in depreciation and amortization charges in the first nine months of 2004, compared with the first nine months of 2003, was primarily due to the increased amortization of regulatory assets ($14 million), partially offset by higher shopping incentive deferrals ($3 million) and deferred interest on the shopping incentives ($4 million).
Other income increased by $2 million in the first nine months of 2004, compared to the same period of 2003, due in part to the absence of costs related to closing the Acme power plant in 2003.
Net interest charges continued to trend lower, decreasing by $3 million in the third quarter of 2004 and $5 million in the first nine months of 2004 from the same periods of 2003, reflecting redemptions and refinancings since the end of the
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third quarter of 2003. TE’s long-term debt redemptions of $230 million and the repricing of $54 million of pollution control notes during the first nine months of 2004 are expected to result in annualized savings of approximately $19 million.
Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded an after-tax credit to net income of $26 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $44 million increase to income, or $26 million net of income taxes.
TE’s cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next two 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.
As of September 30, 2004, TE had approximately $15,000 of cash and cash equivalents, compared with $2 million as of December 31, 2003. The major sources of changes in these balances are summarized below.
Cash provided from (used for) operating activities during the third quarter and first nine months of 2004, compared with the corresponding periods in 2003, were as follows:
Net cash provided from operating activities increased $99 million in the third quarter of 2004 from the third quarter of 2003 as a result of a $36 million increase in cash earnings as described above under “Results of Operations” and a $76 million increase from changes in working capital. These increases were partially offset by a $13 million voluntary pension trust contribution. The largest factor contributing to the change in working capital was an increase in accounts payable. Net cash provided from operating activities increased $222 million in the first nine months of 2004 compared to the same period last year as a result of an $88 million increase in cash earnings and a $147 million increase from changes in working capital, partially offset by the $13 million pension contribution. The change in working capital reflects changes in receivables and payables. The increase from the change in working capital also included the receipt of $12 million in proceeds from the settlement of TE’s claim against NRG, Inc. for the terminated sale of its Bay Shore Plant.
Net cash used for financing activities increased by $157 million and $265 million in the third quarter and the first nine months of 2004 from the same periods of 2003, respectively, and resulted from an increase in net debt redemptions in both periods.
As of September 30, 2004, TE had $40 million of cash and temporary investments (which include short-term notes receivable from associated companies) and $385 million of short-term indebtedness. TE has obtained authorization from the PUCO to incur short-term debt of up to $500 million (including the utility money pool described below). TE had the capability to issue $712 million of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture. Based upon applicable earnings coverage tests, TE could issue up to $370 million of preferred stock (assuming no additional debt was issued) as of September 30, 2004.
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TE has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2004 was 1.28%.
On September 2, 2004, $30.5 million Ohio Water Development Authority pollution control notes were refunded. The new notes were issued in a Dutch Auction interest rate mode, insured by a municipal bond insurance policy and secured by FMBs. On October 1, 2004, Ohio Water Development Authority and Ohio Air Quality Development Authority Series 2000-A pollution control notes aggregating $33.2 million and $34.1 million, respectively, were each remarketed in a Dutch Auction interest rate mode. Each series of notes is insured by a separate municipal bond insurance policy and remains secured by separate FMBs.
TE’s access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. The ratings outlook on all of its securities is stable.
Net cash used for investing activities decreased by $57 million and $51 million in the third quarter and the first nine months of 2004, respectively, from the same periods of 2003. The decreases in both periods were primarily due to the absence of debt remarketing investments of $73 million in the third quarter of 2003 partially offset by increased loans to associated companies of $20 million and $12 million in the third quarter and the first nine months of 2004, respectively.
During the fourth quarter of 2004, capital requirements for property additions are expected to be about $30 million, including $15 million for nuclear fuel. Those requirements are expected to be satisfied from internal cash and short-term borrowings.
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, 2004, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $572 million.
TE sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a “qualified special purpose entity” under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $68 million of off-balance sheet financing as of September 30, 2004.
Included in TE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $167 million and $145 million as of September 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $17 million reduction in fair value as of September 30, 2004.
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 were 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.
In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of TE’s customers elects to obtain power from an
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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. Under the recently approved Rate Stabilization Plan, TE has continuing PLR responsibility to its franchise customers through December 31, 2008.
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 MW of low cost supply to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in TE’s franchise area.
Under that proposal, TE requested:
On February 23, 2004, after consideration of the PUCO Staff comments and testimony as well as those provided by some of the intervening parties, TE made certain modifications to the Rate Stabilization Plan. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process on or before December 1, 2004. In addition to requiring the competitive bid process, the PUCO made other modifications to TE’s revised Rate Stabilization Plan application. Among the major modifications were the following:
On June 18, 2004, TE filed with the PUCO an application for rehearing of the modified version of the Rate Stabilization Plan. Several other parties also filed applications for rehearing. On August 4, 2004, the PUCO issued an Entry on Rehearing modifying its June 9, 2004 Order. The modifications included the following:
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On August 5, 2004, TE accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. TE retains the right to withdraw the modified Rate Stabilization Plan should subsequent adverse action be taken by the PUCO or a court. In the second quarter of 2004, TE implemented the accounting modifications contained in the PUCO’s June 9, 2004 Order, which are consistent with the PUCO’s August 4, 2004 Entry on Rehearing. Those modifications included amortization of transition costs based on extended amortization periods (that are no later than mid-2008 for TE) and the deferral of interest costs on the accumulated deferred shopping incentives. On October 1, 2004, the OCC filed an appeal with the Ohio Supreme Court to overturn the June 9, 2004 PUCO order.
TE filed a proposed competitive bid process which the PUCO modified on October 6, 2004. The PUCO approved the rules for the competitive bid process setting a three-year supply period (2006-2008) requirement for generation service suppliers and a load cap for individual suppliers. In mid-October, the initial auction schedule was revised so that Part 1 and Part 2 auction bidder applications are due November 4 and November 15, 2004, respectively; the trial auction is scheduled to occur on December 3; the auction would commence December 8 and the PUCO will accept or reject the auction results within two business days after the completion of the auction. FirstEnergy has elected to not participate in the auction.
Regulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. TE’s regulatory assets as of September 30, 2004 and December 31, 2003 were $387 million and $459 million, respectively. TE’s regulatory assets are expected to continue to be recovered under the provisions of the transition plan.
On February 26 and 27, 2004, TE, as part of a NERC review of control area operations throughout the United States, participated in a NERC Control Area Readiness Audit. The final audit report, completed on May 6, 2004, identified positive observations and included various recommendations for reliability improvement. FirstEnergy reported completion of those recommendations on June 30, 2004, with one exception related to MISO’s implementation of a voltage stability tool expected to be completed later this year.
With respect to each of the foregoing initiatives, FirstEnergy requested and NERC provided, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. NERC further assembled an independent verification team to confirm implementation of the foregoing initiatives required to be completed as of June 30, 2004. The NERC Verification Team reported, on July 14, 2004, that FirstEnergy has completed the recommended policies, procedures and actions required to be completed by
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June 30, 2004 or summer 2004, with exceptions noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment.
On March 1, 2004, TE filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. – Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy’s control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding.
Various federal, state and local authorities regulate TE with regard to air and water quality and other environmental matters. The effects of compliance on TE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect TE’s earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, TE believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be.
TE is required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. TE cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
TE believes it is complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOxreductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from TE’s Ohio and Pennsylvania facilities. The EPA’s NOxTransport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOxemissions are contributing significantly to ozone levels in the eastern United States. SIPs were required to comply by May 31, 2004 with individual state NOxbudgets. Pennsylvania submitted a SIP that required compliance with the state NOx budgets at TE’s Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that required compliance with the state NOx budgets at TE’s Ohio facilities by May 31, 2004. TE believes its facilities are complying with the state NOxbudgets through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.
TE has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, TE’s proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. TE has accrued liabilities aggregating approximately $0.2 million as of September 30, 2004. TE accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in TE’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
On September 7, 2004, the EPA established new performance standards under Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are
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drawn into a facility’s cooling water system. TE is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance standards. TE is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may be substantial.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy’s service area. On April 5, 2004, the U.S. –Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid’s reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility’s system. The final report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 (see Reliability Initiatives above). FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of September 30, 2004 for any expenditures in excess of those actually incurred through that date.
Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to TE’s normal business operations are pending against TE and its subsidiaries. The most significant not otherwise discussed above are described below.
FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse plant. FirstEnergy is unable to predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002. Further, a petition was filed with the NRC on
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March 29, 2004 by a group objecting to the NRC’s restart order of the Davis-Besse Nuclear Power Station. The Petition seeks, among other things, suspension of the Davis-Besse operating license. A June 2, 2004 ASLB denial of the petition was appealed to the NRC. FENOC and the NRC staff filed opposition briefs on June 24, 2004. If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability or is otherwise made subject to enforcement action based on the Davis-Besse outage, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition and results of operations.
On August 12, 2004, the NRC publicly disclosed that it was notifying FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. TE has a 19.91% interest in the Perry Nuclear Power Plant. The NRC noted that the plant continues to operate safely. The increased oversight will include an extensive NRC team inspection to access the equipment problems and FirstEnergy’s corrective actions. The outcome of this increased oversight is not known at this time.
On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC’s Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and TE and the Davis-Besse extended outage has become the subject of a formal order of investigation. The SEC’s formal order of investigation also encompasses issues raised during the SEC’s examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.
TE prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of TE’s assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. TE’s more significant accounting policies are described below.
TE is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine TE is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. 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.
TE follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class, weather-related impacts and electricity provided by alternative suppliers.
FirstEnergy’s pension and postretirement benefit obligations are allocated to subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. TE’s reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy’s merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used
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in determining the projected benefit obligations for pension and OPEB costs.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy’s pension costs in 2003 and in the first nine months of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution ($13 million funded by TE) to its pension plan. This contribution will mitigate future funding requirements and significantly reduce the year-end minimum pension liability that currently reduces TE’s accumulated other comprehensive income by $9 million.
In connection with FirstEnergy’s initial transition plan, the PUCO determined allowable transition costs based on amounts recorded on TE’s regulatory books. These costs exceeded those deferred or capitalized on TE’s balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). TE uses an effective interest method for amortizing its transition costs, often referred to as a “mortgage-style” amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the Rate Stabilization 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.
In accordance with SFAS 144, TE periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, TE recognizes a loss – calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows).
In accordance with SFAS 143, TE recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of TE’s current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. TE used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants’ current license and settlement based on an extended license term.
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In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, TE evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were to be indicated, TE would recognize a loss – calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. TE’s most recent annual review was completed in the third quarter of 2004, with no impairment of goodwill indicated. The forecasts used in TE’s evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on TE’s future evaluations of goodwill. As of September 30, 2004, TE had $505 million of goodwill.
In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, TE will continue to evaluate its investments as required by existing authoritative guidance.
Issued in May 2004, FSP 106-2 provides guidance on accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. See Note 4 for a discussion of the effect of the federal subsidy provided under the Medicare Act on the consolidated financial statements.
In December 2003, the FASB issued a revised interpretation of ARB 51, referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, TE adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. See Note 2 – Consolidation for a discussion of variable interest entities and the impact of the FIN 46 implementation on the financial statements of TE.
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PENNSYLVANIA POWER COMPANY
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.
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The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets.
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To the Stockholders and Board ofDirectors of PennsylvaniaPower Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania Power Company and its subsidiary as of September 30, 2004, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheet and the statement of capitalization as of December 31, 2003, 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 (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those financial statements) dated February 25, 2004 we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the balance sheet from which it has been derived.
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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 Penn as their power supplier. Penn provides power directly to wholesale customers under previously negotiated contracts. Penn has unbundled the price of electricity into its component elements – including generation, transmission, distribution and transition charges. Its power supply requirements are provided by FES – an affiliated company. Penn’s wholly owned subsidiary, Penn Power Funding LLC, began operations on March 30, 2004.
Earnings on common stock in the third quarter of 2004 increased to $20 million from $17 million in the third quarter of 2003. For the first nine months of 2004, earnings on common stock increased to $56 million from $24 million in the same period of 2003. Earnings on common stock in the first nine months of 2003 included an after-tax credit of $11 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $16 million in the first nine months of 2003. Increased results in both 2004 periods resulted from lower nuclear operating costs and reduced net interest charges. Higher operating revenues partially offset by increased purchased power costs also contributed to the improved results for the nine-month period.
Operating revenues decreased $2.5 million or 1.7% in the third quarter of 2004 from the same period of 2003. Lower revenues resulted principally from a $3 million decrease in revenues from distribution deliveries — partially offset by a $1 million increase in wholesale revenues (primarily to FES) due to increased nuclear generation available for sale. Retail generation sales were lower in all customer classes in the third quarter of 2004. Lower deliveries to residential customers resulted from cooler weather in the third quarter of 2004 compared to the same period of 2003 which reduced air conditioning loads. Weaker economic conditions are reflected by the decrease in distribution deliveries to commercial and industrial customers in the third quarter of 2004.
Operating revenues increased $30 million or 7.6% in the first nine months of 2004 compared with the same period in 2003, principally as a result of a $26 million increase in wholesale revenues (primarily to FES) due to an increase in nuclear generation and higher retail generation revenues. Sales increased in all customer sectors for the first nine months of 2004 compared to the same period of 2003. Increased generation sales and higher unit prices resulted in a $11 million increase in generation revenues. Distribution deliveries increased in all customer classes in the first nine months of 2004 compared with the same period in 2003; but lower unit prices more than offset the effect of the higher deliveries in that period, resulting in a $5 million decrease in revenues. Higher deliveries to the steel sector in the first nine months of 2004 were principally responsible for the increase in kilowatt-hour sales to industrial customers.
Changes in electric generation sales and distribution deliveries in the third quarter and first nine months of 2004 from the same periods of 2003 are summarized in the following table:
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Total operating expenses and taxes decreased $3 million in the third quarter and $6 million in the first nine months of 2004 from the same periods last year. The following table presents changes from the prior year by expense category.
Higher fuel costs in the first nine months of 2004, compared with the same period of 2003, resulted from increased nuclear generation. Purchased power costs increased in the first nine months of 2004 compared with the same period of 2003 reflecting higher unit costs and increased kilowatt-hour purchases to meet higher retail generation requirements. The decrease in nuclear operating costs was due to the absence of refueling outages in 2004 at Beaver Valley Unit 1 (65.00% interest), Perry plant (5.24% interest) and Beaver Valley Unit 2 (13.74% interest) in the first, second and third quarters of 2003, respectively.
Net interest charges continued to trend lower, decreasing by approximately $2 million and $6 million in the third quarter and first nine months of 2004, respectively, from the same periods last year, reflecting mandatory and optional debt redemptions of $63 million since the end of the third quarter of 2003.
Upon adoption of SFAS 143 in the first quarter of 2003, Penn recorded an after-tax credit to net income of $11 million. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was an $18 million increase to income, or $11 million net of income taxes.
Penn’s cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing Penn’s net debt and preferred stock outstanding. Penn received a $25 million equity contribution from OE in the third quarter of 2004. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next two 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.
As of September 30, 2004, Penn had $38,000 of cash and cash equivalents, compared with $40,000 as of December 31, 2003. The major sources of changes in these balances are summarized below.
Cash flows provided from operating activities during the third quarter and first nine months of 2004, compared with the corresponding periods in 2003, were as follows:
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Net cash from operating activities decreased $9 million in the third quarter of 2004 compared to the same quarter of 2003 primarily due to a $13 million voluntary pension trust contribution. The decrease was partially offset by a $3 million increase in cash earnings as described above under “Results of Operations”. During the first nine months of 2004, net cash from operating activities increased $17 million due to a $50 million increase in cash earnings partially offset by a $20 million decrease from changes in working capital (including changes in accounts receivable, accounts payable and accrued taxes) and the $13 million pension contribution.
In the third quarter of 2004, net cash used for financing activities decreased to $8 million from $43 million from the same quarter last year. In the first nine months of 2004, net cash used for financing activities decreased to $52 million from $72 million in the same period last year. These decreases primarily resulted from a $25 million equity contribution from OE in the third quarter of 2004 and reduced common stock dividends to OE in both periods.
Penn had $592,000 of cash and temporary investments (which include short-term notes receivable from associated companies) and $22 million of short-term indebtedness as of September 30, 2004. Penn has obtained authorization from the SEC to incur short-term debt up to its charter limit of $46 million (including the utility money pool). Penn had the capability to issue $497 million of additional FMB on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests, Penn could issue up to $526 million of preferred stock (assuming no additional debt was issued) as of September 30, 2004.
Penn has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Available bank borrowings include $1.75 billion from FirstEnergy’s and OE’s revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2004 was 1.28%.
Penn’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of OE and FirstEnergy. The ratings outlook on all of its securities is stable.
On July 22, 2004, S&P updated its analysis of U.S. utility FMB in response to changes in the industry. As a result of its revised methodology for evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility companies, including Penn. Penn’s FMB credit rating was upgraded to BBB from BBB-.
On August 26, 2004, S&P stated that a favorable outcome of FirstEnergy’s Ohio Rate Stabilization Plan auction process and a favorable resolution of pending environmental litigation would support a higher ratings outlook, or possibly a higher rating. S&P noted that a ratings upgrade in 2004 does not appear likely because those major issues would most likely not be resolved before the end of 2004. On September 14, 2004, S&P stated that FirstEnergy’s voluntary $500 million contribution to its pension plan was credit neutral.
Net cash used for investing activities totaled $28 million in the third quarter of 2004 compared to $2 million in the same quarter of 2003. The $26 million increase reflects an increase in capital expenditures and a decrease in loan repayments from associated companies. For the first nine months of 2004, net cash used for investing activities was $53
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million compared to $18 million in the same period of 2003. The $35 million increase was primarily due to a $28 million decrease in loan repayments from associated companies.
During the fourth quarter of 2004, capital requirements for property additions and capital leases are expected to be about $26 million, including $10 million for nuclear fuel. Penn has additional requirements of approximately $1 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. Those requirements are expected to be satisfied from internal cash and short-term credit arrangements.
Included in Penn’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $52 million and $50 million as of September 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of September 30, 2004.
Beginning in 1999, Penn’s customers were able to select alternative energy suppliers. Penn continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. The PPUC authorized Penn’s rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. Penn has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as its PLR obligation.
Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Penn’s regulatory assets are expected to continue to be recovered under the provisions of its regulatory plan. Penn’s regulatory assets totaled $28 million as of December 31, 2003. Changes in Penn’s net regulatory asset components through September 30, 2004 resulted in net regulatory liabilities of $4 million as of September 30, 2004.
In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and required additional reporting on reliability. The PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order
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approving the revised reliability benchmark and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. The Order permitted Pennsylvania utilities to file in a separate proceeding to revise the recomputed benchmarks and standards if they have evidence, such as the impact of automated outage management systems, on the accuracy of the PPUC computed reliability indices. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards due to their implementation of automated outage management systems following restructuring. No procedural schedule or hearing date has been set for this proceeding. FirstEnergy is unable to predict the outcome of this proceeding.
Various federal, state and local authorities regulate Penn with regard to air and water quality and other environmental matters. The effects of compliance on Penn with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect Penn’s earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, Penn believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be.
Penn is required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. Penn cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant which is owned by OE and Penn. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of “best available control technology” and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase trial to address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant has been rescheduled to January 2005 by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, that the remedies it “may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act.” The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on Penn’s financial condition and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of September 30, 2004.
Penn believes it is complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOxreductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from Penn’s Ohio and Pennsylvania facilities. The EPA’s NOxTransport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOxemissions are contributing significantly to ozone levels in the eastern United States. SIPs were required to comply by May 31, 2004 with individual state NOxbudgets. Pennsylvania submitted a SIP that required compliance with the state NOx budgets at Penn’s Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that
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required compliance with the state budgets at Penn’s Ohio facilities by May 31, 2004. Penn believes its facilities are complying with the state NOx budgets through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.
On September 7, 2004, the EPA established new performance standards under Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are drawn into a facility’s cooling water system. Penn is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance standards. Penn is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may be substantial.
Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penn’s normal business operations are pending against Penn, the most significant of which are described herein.
On August 12, 2004, the NRC publicly disclosed that it was notifying FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. Penn owns a 5.24% interest in the Perry Nuclear Power Plant. The NRC noted that the plant continues to operate safely. The increased oversight will include an extensive NRC team inspection to access the equipment problems and FirstEnergy’s corrective actions. The outcome of this increased oversight is not known at this time.
Penn prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of Penn’s assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the
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application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Penn’s more significant accounting policies are described below.
Penn is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Penn is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. Penn regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.
Penn follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, weather-related impacts and electricity provided by alternative suppliers.
FirstEnergy’s pension and postretirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. Penn’s reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy’s pension costs in 2003 and in the first nine months of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution ($13 million funded by Penn) to its pension plan. This contribution will mitigate future funding requirements and significantly reduce the year-end minimum pension liability that currently reduces Penn’s accumulated other comprehensive income by $12 million.
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In accordance with SFAS 144, Penn periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, Penn recognizes a loss – calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows).
In accordance with SFAS 143, Penn recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of Penn’s current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Penn used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants’ current license and settlement based on an extended license term.
In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004.
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JERSEY CENTRAL POWER & LIGHT COMPANY
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.
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The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these balance sheets.
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To the Stockholders and Board ofDirectors of Jersey CentralPower & Light Company:
We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of September 30, 2004, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
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JCP&L is a wholly owned electric utility subsidiary of FirstEnergy. JCP&L conducts business in northern, western and east central New Jersey, providing regulated transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier. JCP&L has unbundled the price for electricity into its component elements – including generation, transmission, distribution and transition charges.
As discussed in Note 2 to the Consolidated Financial Statements, JCP&L’s results for the third quarter and first nine months of 2003 have been restated to correct the amounts reported for operating expenses. JCP&L’s costs which were originally recorded as operating expenses and should have been capitalized to construction were $5.8 million ($3.4 million after-tax) and $9.0 million ($5.3 million after-tax) in the third quarter of 2003 and the first nine months of 2003, respectively. The impact of these adjustments was not material to JCP&L’s Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003. In addition, as further discussed in Note 8 to the Consolidated Financial Statements, amounts for purchased power, other operating costs and provisions for depreciation and amortization in JCP&L’s 2003 Consolidated Statements of Income were reclassified to conform with the current year presentation of generation commodity costs. These reclassifications did not change previously reported results in 2003.
Earnings on common stock in the third quarter of 2004 decreased to $52 million from $67 million in the third quarter of 2003. For the first nine months of 2004, earnings on common stock increased to $102 million from $80 million in the same period of 2003. Earnings in the third quarter and the first nine months of 2003 included non-cash charges aggregating $13 million ($8 million after-tax) and $172 million ($103 million after tax), respectively, due to a rate case decision disallowing cost recovery (see Regulatory Matters). Earnings before the non-cash charges were $75 million and $183 million for the third quarter and the first nine months of 2003, respectively. The decrease in earnings excluding the non-cash charges in 2003 was primarily due to lower operating revenues in both periods which were partially offset by lower other operating costs in the third quarter of 2004 and lower purchased power costs in the first nine months of 2004 compared to the same periods of 2003.
Operating revenues decreased by $35 million or 4.7% in the third quarter of 2004 from the same period of 2003 principally from lower retail generation and distribution throughput revenues and a $1 million decrease in wholesale sales revenues. Retail generation sales decreased by 12.4% due to an 8.3 percentage point increase in electric generation services provided by alternative suppliers as a percent of total sales deliveries in JCP&L’s franchise area. Lower retail generation sales were partially offset by higher unit prices reflecting the results of the BGS auction (see Regulatory Matters) resulting in a combined $11 million decrease in revenues. Operating revenues decreased $187 million or 9.6% in the first nine months of 2004, compared with the same period in 2003, reflecting decreased retail generation sales and distribution throughput revenues and a $56 million decrease in wholesale revenues. JCP&L entered into long-term power purchase agreements in connection with the divestiture of its generation facilities and sold any power in excess of its retail customer needs to the wholesale market. The long-term purchase agreements ended after the first quarter of 2003 and as a result, sales to the wholesale market subsequently decreased. Retail generation sales decreased by 18.6% in the first nine months of 2004 reflecting the same trend in customer shopping (increases of 4.5, 22.2 and 56.2 percentage points for residential, commercial and industrial customers, respectively). The impact of lower retail generation sales was partially offset by higher unit prices resulting in a $10 million decrease in retail generation revenues.
Revenues from distribution throughput decreased by $21 million in the third quarter of 2004 as compared to the third quarter of 2003. Distribution deliveries to residential customers decreased 3.1% due to cooler weather which reduced air conditioning loads. Weaker economic conditions reduced distribution deliveries to commercial and industrial customers in the third quarter of 2004 compared to the same period in 2003. The decreased distribution deliveries coupled with lower unit prices reduced revenues from electricity throughput by $21 million in the third quarter of 2004. The increase in distribution deliveries for the first nine months of 2004 resulted from higher deliveries to the residential (3.0%) and commercial (1.5%) sectors. Lower unit prices offset the increased volume sales resulting in a $114 million decrease in distribution revenues. In July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision (see Regulatory Matters) which reduced JCP&L’s distribution rates effective August 1, 2003. Partially offsetting the lower base distribution rates were higher energy, MTC and SBC rates, with the increase in energy and MTC rates concentrated in the summer billing months. These did not result in material earnings impact due to deferral accounting.
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Changes in distribution deliveries in the third quarter and first nine months of 2004 compared with the same periods of 2003 are summarized in the following table:
Total operating expenses and taxes decreased by $19 million in the third quarter and $205 million in the first nine months of 2004 compared to the same periods of 2003. The following table presents changes from the prior year by expense category.
Purchased power costs and the provision for depreciation and amortization in 2003 included non-cash charges for amounts disallowed in the July 2003 JCP&L rate case decision (see Regulatory Matters) – $153 million of deferred purchased power costs and $19 million charged to depreciation and amortization in the first nine months of 2004. Excluding the disallowed deferred energy costs in the second quarter of 2003, purchased power costs decreased by $2 million in the third quarter and $78 million in the first nine months of 2004 from the same periods of 2003. Purchased power costs in both periods reflected lower kilowatt-hour purchases due to reduced generation sales requirements, partially offset by higher unit prices from changes in deferred energy and capacity costs. The decrease in other operating costs of $12 million in the third quarter of 2004 is attributable to lower payroll and employee benefits costs and the absence in 2004 of storm restoration costs incurred in the third quarter of 2003. Other operating costs increased $4 million for the first nine months of 2004 due to JCP&L’s accelerated reliability program. Excluding the amounts disallowed in the July 2003 rate decision ($13 million and $19 million in the third quarter and first nine months of 2003, respectively), depreciation and amortization increased $20 million and $25 million in the third quarter and the first nine months of 2004, respectively, reflecting an increased level of regulatory asset amortization associated with higher MTC and SBC revenues, partially offset by lower depreciation rates.
Net interest charges for the 2004 periods reflect reductions associated with debt redeemed since the end of the third quarter of 2003. Interest expense in the third quarter of 2004 included a $2 million adjustment relating to $300 million of notes issued in April 2004 that increased net interest charges for the period.
JCP&L’s cash requirements in 2004 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 two years, JCP&L expects to meet its contractual obligations with cash from operations. Thereafter, JCP&L expects to use a combination of cash from operations and funds from the capital markets.
JCP&L’s cash and cash equivalents were $0.3 million as of September 30, 2004 and December 31, 2003.
Cash provided from operating activities during the third quarter and first nine months of 2004, compared to the corresponding periods of 2003, were as follows:
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Net cash from operating activities increased $87 million in the third quarter of 2004 compared to the same period in 2003. The increase included a $174 million increase from changes in working capital, partially offset by a $62 million voluntary pension trust contribution and a $25 million decrease in cash earnings as described under “Results of Operations”. The change in working capital primarily reflects an increase in accounts payable and $52.8 million received in connection with restructuring a NUG power contract. Net cash from operating activities increased $209 million in the first nine months of 2004 compared to the same period in 2003 due to a $348 million increase from changes in working capital, partially offset by a $77 million decrease in cash earnings and the $62 million pension contribution. The change in working capital primarily reflects lower accounts receivable and prepayments and higher accounts payable and accrued tax balances.
Net cash used for financing activities in the third quarter of 2004 was $48 million compared to net cash provided from financing activities of $9 million in the third quarter of 2003. The change primarily reflects a $40 million increase in common stock dividends to FirstEnergy and a $17 million increase in net debt and preferred stock redemptions. Net cash used for financing activities increased to $137 million in the first nine months of 2004 compared to $63 million in the same period of 2003. The increase resulted from a $142 million increase in net debt and preferred stock redemptions, partially offset by a $68 million decrease in common stock dividends to FirstEnergy.
JCP&L has obtained authorization from the SEC to incur short-term debt up to its charter limit of $419 million (including the utility money pool). JCP&L may issue FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture, provided, however, that under a provision of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of September 30, 2004, JCP&L had the capability to issue $490 million of additional senior notes upon the basis of FMB collateral. Based upon applicable earnings coverage tests, JCP&L could issue a total of $406 million of preferred stock (assuming no additional debt was issued) as of September 30, 2004.
JCP&L has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2004 was 1.28%.
JCP&L’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook on all such securities is stable.
On July 22, 2004, S&P updated its analysis of U.S. utility FMB in response to changes in the industry. As a result of its revised methodology for evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility companies including JCP&L. JCP&L’s FMB credit rating was upgraded to BBB+ from BBB.
On August 26, 2004, S&P stated that a favorable outcome of FirstEnergy’s Ohio Rate Stabilization Plan auction process and a favorable resolution of pending environmental litigation would support a higher ratings outlook, or possibly a higher rating. S&P noted that a ratings upgrade in 2004 does not appear likely because those major issues would most likely not be resolved before the end of 2004. On September 14, 2004, S&P stated that FirstEnergy’s $500 million voluntary contribution to its pension plan was credit neutral.
Net cash used for investing activities totaled $52 million and $137 million in the third quarter and first nine months of 2004, respectively, compared to $27 million and $7 million in the respective periods of 2003. The change in both periods was due to a decrease in loan repayments from associated companies and higher capital expenditures in 2004.
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During the fourth quarter of 2004, capital requirements for property additions are expected to be about $27 million. JCP&L has additional requirements of approximately $5 million for maturing long-term debt during the remainder of 2004. Those requirements are expected to be satisfied from internal cash and short-term credit arrangements.
Market Risk Information
JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. FirstEnergy’s Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices.
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 2004 is summarized in the following table:
Derivatives included on the Consolidated Balance Sheet as of September 30, 2004:
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:
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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, 2004.
Included in JCP&L’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $73 million and $69 million as of September 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7 million reduction in fair value as of September 30, 2004.
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 transmission and distribution systems, which remain regulated. To support customer choice, rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs.
On July 16, 2004, JCP&L filed the Phase II rate filing with the NJBPU which requested an increase in base rates of $36 million, reflecting the recovery of system reliability costs and a 9.75% return on equity. The filing also
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requests an increase to the MTC deferred balance recovery of approximately $20 million annually. Discovery/settlement conferences are ongoing. The filing fulfills the NJBPU requirement that a Phase II proceeding be conducted and that any expenditures and projects undertaken by JCP&L to increase its system reliability be reviewed.
Regulatory assets are costs which have been authorized by the NJBPU and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of JCP&L’s regulatory assets are expected to continue to be recovered under the provisions of the regulatory proceedings discussed above. JCP&L’s regulatory assets were $2.1 billion and $2.6 billion as of September 30, 2004 and December 31, 2003, respectively.
JCP&L has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, JCP&L’s proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. JCP&L has accrued liabilities aggregating approximately $45.8 million as of September 30, 2004. JCP&L accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in JCP&L’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy’s service area. On April 5, 2004, the U.S. –Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid’s reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility’s system. The final report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification
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team on July 14, 2004 (see Reliability Initiatives below). FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of September 30, 2004 for any expenditures in excess of those actually incurred through that date.
On April 5, 2004, the U.S. – Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outages. The Final Report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force activities that were directed toward FirstEnergy and reported completion on June 30, 2004.
Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to JCP&L’s normal business operations are pending against JCP&L, the most significant of which are described herein.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, and strict products liability. In November 2003, the trial court granted JCP&L’s motion to decertify the class and denied plaintiffs’ motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Court issued a decision on July 8, 2004, affirming the decertification of the originally certified class but remanding for certification of a class limited to those customers directly impacted by the outages of transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Court. JCP&L is unable to predict the outcome of these matters and no liability has been accrued as of September 30, 2004.
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JCP&L prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of JCP&L’s assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. JCP&L’s more significant accounting policies are described below.
JCP&L is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine JCP&L is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. 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.
Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management’s intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management’s expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. JCP&L continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, JCP&L enters into commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments.
JCP&L follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class and electricity provided by alternative suppliers.
FirstEnergy’s pension and post-retirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. JCP&L’s reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.
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In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy’s pension costs in 2003 and in the first nine months of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution ($62 million funded by JCP&L) to its pension plan. This contribution will mitigate future funding requirements and significantly reduce the year-end minimum pension liability that currently reduces JCP&L’s accumulated other comprehensive income by $48 million.
In accordance with SFAS 144, JCP&L periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment is indicated, 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).
In accordance with SFAS 143, JCP&L recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of JCP&L’s current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. JCP&L used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes.
In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, JCP&L evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were to be indicated, JCP&L would recognize a loss – calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. JCP&L’s most recent annual review was completed in the third quarter of 2004, with no impairment indicated. The forecasts used in JCP&L’s evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on JCP&L’s future evaluations of goodwill. In the first nine months of 2004, JCP&L reduced goodwill by $5 million for pre-merger interest received on an income tax refund and other tax benefits. As of September 30, 2004, JCP&L had approximately $2 billion of goodwill.
In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be
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effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004.
In December 2003, the FASB issued a revised interpretation of ARB 51, referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, JCP&L adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on JCP&L’s consolidated financial statements. See Note 2 – Consolidation for a discussion of variable interest entities.
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METROPOLITAN EDISON COMPANY
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.
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The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets.
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To the Stockholders and Board ofDirectors of Metropolitan Edison Company:
We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of September 30, 2004, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 8 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
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Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated transmission and distribution services. Met-Ed also provides generation services to those customers electing to retain Met-Ed as their power supplier. Met-Ed has unbundled the price for electricity into its component elements – including generation, transmission, distribution and transition charges.
Net income in the third quarter of 2004 increased to $17 million from $14 million in the third quarter of 2003. The increase in net income resulted principally from higher operating revenues and lower interest charges partially offset by higher purchased power and other operating costs. For the first nine months of 2004, net income decreased to $42 million compared to $44 million in the same period of 2003. The decrease in net income resulted from higher purchased power, depreciation and amortization, and other operating costs partially offset by higher operating revenues. As further discussed in Note 8 to the Consolidated Financial Statements, amounts for purchased power, other operating costs and provisions for depreciation and amortization in Met-Ed’s 2003 Consolidated Statements of Income were reclassified to conform with the current year presentation of generation commodity costs. These reclassifications did not change previously reported results in 2003.
Operating revenues increased by $24 million or 9.3% in the third quarter of 2004 compared with the same period of 2003, principally due to higher revenues from distribution deliveries ($8 million), retail generation ($6 million) and an $8 million increase in transmission revenues. Higher retail generation sales revenues reflected a 10.9% increase in generation sales primarily due to commercial and industrial generation customers returning to Met-Ed from alternative suppliers. The increase in commercial and industrial sales was partially offset by lower retail generation unit prices in all customer classes. Higher revenues from distribution throughput were due to a 2.8% increase in distribution deliveries and higher unit prices. An improving economy in Met-Ed’s franchise area resulted in increased distribution deliveries to commercial and industrial customers. The higher distribution unit prices are due to the PPUC Restructuring Settlement order (see Regulatory Matters) with a corresponding decrease in retail generation unit prices.
Operating revenues increased by $58 million or 8.0% in the first nine months of 2004 compared with the same period in 2003, primarily due to increases of $29 million and $18 million in distribution and retail generation sales revenues, respectively, and higher transmission revenues. Sales of electric generation by alternative suppliers as a percent of total sales delivered to commercial and industrial customers in Met-Ed’s franchise area decreased by 3.2 and 19.4 percentage points, respectively. The decrease in customers shopping resulted in an 11.3% increase in retail generation sales which was partially offset by the lower generation unit prices discussed above. Higher revenues from electricity throughput resulted primarily from higher unit prices, an increase in the retail customer base and an improving economy, partially offset by cooler weather in the summer months of 2004.
The significant decrease in customer shopping over the past year reflects Met-Ed’s low generation price as the provider of last resort. Alternative suppliers have not been able to match that price (shopping credit) by a sufficient margin in order to ensure profitability, particularly to the industrial sector.
Changes in distribution deliveries in the third quarter and first nine months of 2004 from the same periods of 2003 are summarized in the following table:
Total operating expenses and taxes increased $23 million in the third quarter and $63 million in the first nine months of 2004 compared to the same periods of 2003. The following table presents changes from the prior year by expense category.
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Higher purchased power costs in the third quarter and first nine months of 2004, compared to the same periods of 2003, were due to increased PLR kilowatt-hour purchases from FES. Other operating costs increased by $4 million in the third quarter of 2004 primarily due to higher transmission costs, which were assumed by Met-Ed earlier in the year due to a change in the power supply agreement with FES. Other operating costs increased by $12 million in the first nine months of 2004 due to higher vegetation management and transmission costs, partially offset by lower costs associated with storm restoration activities in 2004. Depreciation and amortization expenses were $2 million higher in the first nine months of 2004 due to increased amortization of regulatory assets being recovered through the CTC rate. General taxes increased by $2 million due to gross receipt taxes and higher payroll taxes related to the transfer of employees to Met-Ed from GPUS.
Net interest charges decreased by $0.6 million in the third quarter and $0.3 million in the first nine months of 2004 compared to the same periods in 2003 primarily due to the redemption of subordinated debentures related to the 7.35% trust preferred securities in June 2004 and the redemption of $50 million of long-term debt in the first quarter of 2004. The decrease in net interest charges from these redemptions was partially offset by the issuance of $250 million of senior notes at the end of the first quarter of 2004 and the elimination of deferred interest for PLR energy costs in the third quarter of 2003.
Met-Ed’s cash requirements in 2004 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 two 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.
As of September 30, 2004, Met-Ed had $120,000 of cash and cash equivalents compared with $121,000 as of December 31, 2003. The major sources of changes in these balances are summarized below.
Cash provided from (used for) operating activities during the third quarter and first nine months of 2004, compared with the corresponding periods of 2003, were as follows:
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Net cash used for operating activities increased $29 million in the third quarter of 2004 from the third quarter of 2003 due to a $66 million increase from changes in working capital and a $2 million increase in cash earnings as described above under “Results of Operations”, offset by a $39 million voluntary pension trust contribution. The largest factors contributing to the increase in working capital was a $77 million increase in accounts payable partially offset by a $14 million increase in accounts receivable.
Net cash provided from operating activities decreased $25 million in the first nine months of 2004 from the same period of 2003 as a result of the $39 million pension trust contribution, a $24 million decrease in cash earnings, partially offset by a $38 million increase in working capital. Working capital increased primarily due to a $28 million decrease in accounts receivable and a change in accrued taxes, accrued interest and other current liabilities aggregating $27 million. Partially offsetting the increase in working capital was a decrease of $12 million in accounts payable and an increase in prepayments and other current assets of $13 million.
In the third quarter of 2004, net cash provided from financing activities decreased to $14 million compared with $29 million in the third quarter of 2003 due to a $46 million increase in debt redemptions and a $3 million increase in common stock dividends, partially offset by a $34 million increase in short term borrowings. In the first nine months of 2004 net cash provided from financing activities was $21 million compared to $42 million of net cash used for financing activities in the first nine months of 2003. The change reflected a $34 million decrease in debt redemptions and a $37 million increase in short-term borrowings, partially offset by an $8 million increase in common stock dividends to FirstEnergy.
In March 2004, Met-Ed completed a receivables financing arrangement that provides borrowings of up to $80 million. The borrowing rate is based on bank commercial paper rates. Met-Ed is required to pay an annual facility fee of 0.30% on the entire finance limit. The facility was drawn in the third quarter of 2004 for $70 million and matures on March 29, 2005.
As of September 30, 2004, Met-Ed had approximately $23 million of cash and temporary investments (which include short-term notes receivable from associated companies) and $70 million of short-term indebtedness. Met-Ed has obtained authorization from the SEC to incur short-term debt of up to $250 million (including the utility money pool). Under the terms of its senior note indenture, Met-Ed is no longer permitted to issue FMB so long as senior notes are outstanding. Met-Ed has no restrictions on the issuance of preferred stock.
Met-Ed has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2004 was 1.28%.
Met-Ed’s access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. On August 26, 2004, S&P lowered its rating on certain Met-Ed Senior Notes to BBB- from BBB. The rationale for the ratings change was that Met-Ed’s senior secured notes, in aggregate, now comprise greater than 80% of Met-Ed’s total debt outstanding. According to the terms of the senior note indenture, once the 80% threshold is reached, the collateral mortgage bond security falls away and all senior secured notes that were secured by Met-Ed’s senior note indenture become unsecured. The one notch lower rating reflects this loss of collateral security. The BBB senior secured rating on Met-Ed’s first mortgage bonds remained unchanged.
Also on August 26, 2004, S&P stated that a favorable outcome of FirstEnergy’s Ohio Rate Stabilization Plan auction process and a favorable resolution of pending environmental litigation would support a higher ratings outlook, or possibly a higher rating. S&P noted that a ratings upgrade in 2004 does not appear likely because those major issues would most likely not be resolved before the end of 2004. On September 14, 2004, S&P stated that FirstEnergy’s $500 million voluntary contribution to its pension plan was credit neutral.
In the third quarter of 2004, net cash used for investing activities totaled $7 million, compared to net cash provided from investing activities of $8 million in the third quarter of 2003. A $4 million increase in property additions and a $9 million capital transfer from FESC contributed to the increase in cash used in investing activities. In the first nine months of 2004, net cash used in investing activities totaled $64 million, compared to $42 million for the same period of 2003. A $5 million increase in loans to associated companies, and a $17 million increase in property additions and the capital transfer from FESC in the third quarter contributed to the increase.
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During the fourth quarter of 2004, capital requirements for property additions are expected to be about $19 million. Those requirements are expected to be satisfied from internal cash and short-term credit arrangements.
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.
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 first nine months of 2004 is summarized in the following table:
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:
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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, 2004.
Included in Met-Ed’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $123 million and $114 million as of September 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12 million reduction in fair value as of September 30, 2004.
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 transmission and distribution systems, which remain regulated. The PPUC authorized Met-Ed’s rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative 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.
In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed to defer, for future recovery, energy costs in excess of amounts reflected in its capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. Met-Ed established a $103 million reserve in 2002 for its PLR deferred energy costs incurred prior to its acquisition by FirstEnergy, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. The reserve increased goodwill by an aggregate net of tax amount of $60.3 million.
On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed Met-Ed to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Met-Ed’s restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 20, 2001 order in its entirety. The PPUC directed Met-Ed to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day’s notice. In response to that order, Met-Ed filed supplements to its tariffs to become effective October 24, 2003.
On October 8, 2003, Met-Ed filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC’s findings would not impair its rights to recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed for the NUG trust fund refund and, denying Met-Ed’s other clarification requests and granting ARIPPA’s petition with respect to the retroactive accounting treatment of the changes to the CTC
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rate/shopping credit swap. On October 22, 2003, Met-Ed filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC’s finding that requires Met-Ed to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis.
On October 27, 2003, one Commonwealth Court judge issued an Order denying Met-Ed’s Objection without explanation. Due to the vagueness of the Order, Met-Ed, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed, in order to preserve its rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC’s October 2 and October 16 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed’s Objection was intended to be denied on the merits. In addition to these findings, Met-Ed, in compliance with the PPUC’s Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC’s findings in their Orders.
Met-Ed purchases a portion of its PLR requirements from FES through a wholesale power sale agreement. The PLR sale is 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 retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed’s exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of Met-Ed’s unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previously allowed under the PPUC’s order. Met-Ed is authorized to continue deferring differences between NUG contract costs and current market prices.
Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of Met-Ed’s regulatory assets are expected to continue to be recovered under the provisions of its regulatory plan. Met-Ed’s regulatory assets were $785 million and $1.03 billion as of September 30, 2004 and December 31, 2003, respectively.
Met-Ed has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, Met-Ed’s proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Met-Ed has accrued liabilities aggregating approximately $28,000 as of September 30, 2004. Met-Ed accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in Met-Ed’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy’s service area. On April 5, 2004, the U.S. –Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid’s reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility’s system. The final report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 (see Reliability Initiatives below). FirstEnergy’s implementation of these recommendations
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included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of September 30, 2004 for any expenditures in excess of those actually incurred through that date.
With respect to each of the foregoing initiatives, FirstEnergy requested and NERC provided, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. NERC further assembled an independent verification team to confirm implementation of the foregoing initiatives required to be completed as of June 30, 2004. The NERC Verification Team reported, on July 14, 2004, that FirstEnergy has completed the recommended policies, procedures, and actions required to be completed by June 30, 2004 or summer 2004, with exceptions noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment.
In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and required additional reporting on reliability. The PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order approving the revised reliability benchmark and standards, including revised benchmarks and standards for Met-Ed. The Order permitted Pennsylvania utilities to file in a separate proceeding to revise the recomputed benchmarks and standards if they have evidence, such as the impact of automated outage management systems, on the accuracy of the PPUC computed reliability indices. Met-Ed filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, seeking amendment of the benchmarks and standards due to their implementation of automated outage management systems following restructuring. No procedural schedule or hearing date has been set for this proceeding. Met-Ed is unable to predict the outcome of this proceeding.
On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed’s “service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring” in Pennsylvania. Hearings were held in early August 2004. On September 30, 2004, Met-Ed filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settlement, Met-Ed agreed to enhance service reliability, performance reporting and communications with customers and together with Penn and Penelec, to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. In November 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.
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Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Met-Ed’s normal business operations, are pending against Met-Ed, the most significant of which are described above.
Met-Ed prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of Met-Ed’s assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Met-Ed’s more significant accounting policies are described below.
Met-Ed is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Met-Ed is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. 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.
Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management’s intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management’s expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. Met-Ed continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Met-Ed enters into commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments.
Met-Ed follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class and electricity provided by alternative suppliers.
FirstEnergy’s pension and postretirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. Met-Ed’s reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.
In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of
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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.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy’s pension costs in 2003 and in the first nine months of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution ($39 million funded by Met-Ed) to its pension plan. This contribution will mitigate future funding requirements and significantly reduce the year-end minimum pension liability that currently reduces Met-Ed’s accumulated other comprehensive income by $33 million.
In accordance with SFAS 144, Met-Ed periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, Met-Ed recognizes a loss – calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows).
In accordance with SFAS 143, Met-Ed recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of Met-Ed’s current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Met-Ed used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes.
In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, Met-Ed evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were to be indicated, Met-Ed would recognize a loss – calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. Met-Ed’s most recent annual review was completed in the third quarter of 2004, with no impairment indicated. The forecasts used in Met-Ed’s evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on Met-Ed’s future evaluations of goodwill. In the first nine months of 2004, Met-Ed reduced goodwill by $6 million for pre-merger interest received on an income tax refund and other tax benefits. As of September 30, 2004, Met-Ed had $878 million of goodwill.
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In December 2003, the FASB issued a revised interpretation of ARB 51, referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, Met-Ed adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on Met-Ed’s consolidated financial statements. See Note 2 – Consolidation for a discussion of variable interest entities.
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PENNSYLVANIA ELECTRIC COMPANY
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.
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The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these balance sheets.
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To the Stockholders and Board ofDirectors of Pennsylvania Electric Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of September 30, 2004, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.
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Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern, western and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier. Penelec has unbundled the price for electricity into its component elements – including generation, transmission, distribution and transition charges.
As discussed in Note 2 to the Consolidated Financial Statements, Penelec’s quarterly results for the third quarter and first nine months of 2003 have been restated to correct the amounts reported for operating expenses. Penelec’s costs which were originally recorded as operating expenses and should have been capitalized to construction were $2.0 million ($1.2 million after-tax) and $2.7 million ($1.6 million after-tax) in the third quarter of 2003 and first nine months of 2003, respectively. The impact of these adjustments was not material to Penelec’s Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003. In addition, as further discussed in Note 8 to the Consolidated Financial Statements, amounts for purchased power, other operating costs and provisions for depreciation and amortization in Penelec’s 2003 Consolidated Statements of Income were reclassified to conform with the current year presentation of generation commodity costs. These reclassifications did not change previously reported results in 2003.
Net income in the third quarter of 2004 increased to $18 million from $5 million in the third quarter of 2003. For the first nine months of 2004, net income increased to $27 million compared to $19 million in the same period of 2003. Net income in the first nine months of 2003 included an after-tax credit of $1 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $18 million in the first nine months of 2003. Increased results in both 2004 periods resulted principally from higher operating revenues and lower other operating costs partially offset by higher net interest charges in both periods and increased purchased power costs in the first nine months of 2004.
Operating revenues increased by $12 million or 5.0% in the third quarter of 2004 compared with the same period of 2003, primarily due to higher revenues from distribution deliveries and wholesale sales ($1 million) — partially offset by lower retail generation revenues. Revenues from distribution deliveries increased by $10 million resulting from higher unit prices and a 3.5% increase in electricity throughput. Distribution deliveries increased to commercial and industrial customers reflecting an improving economy in Penelec’s service area. A $2 million decrease in retail generation revenues was due to lower unit prices which were partially offset by a 3.8% increase in retail generation kilowatt-hour sales due to generation customers returning from alternative suppliers. The lower retail generation unit prices are due to the PPUC Restructuring Settlement order (see Regulatory Matters).
For the first nine months of 2004, operating revenues increased $24 million or 3.3% compared to the same period in 2003, reflecting a 3.3% increase in distribution deliveries that produced a $30 million increase in revenues. The impact of a 4.4% increase in retail generation sales was more than offset by lower unit prices that reduced revenues by $6 million. The increase in retail generation sales reflected the economic factors discussed above and the decrease in customer shopping.
The significant decrease in customer shopping over the past year reflects Penelec’s low generation price as the provider of last resort. Alternative suppliers have not been able to match that price (shopping credit) by a sufficient margin in order to ensure profitability, particularly to the industrial sector.
Changes in electric generation sales and distribution deliveries in the third quarter and the first nine months of 2004 from the corresponding periods of 2003 are summarized in the following table:
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Total operating expenses and taxes decreased $2 million in the third quarter of 2004 and increased $11 million in the first nine months of 2004 from the same periods of 2003. The following table presents changes from the prior year by expense category.
Higher purchased power costs in the first nine months of 2004, compared with the same period of 2003, were due to higher kilowatt-hour purchases to meet increased generation sales requirements, partially offset by lower unit costs. The decreases in other operating costs in the 2004 periods resulted primarily from higher levels of energy delivery construction activities in 2004, compared to more maintenance activities last year, and lower payroll and employee benefits costs. The decrease in other operating costs in the first nine months of 2004 was partially offset by higher vegetation management costs.
Net interest charges increased by $1 million in the third quarter of 2004 and $5 million in the first nine months of 2004 compared with 2003, primarily due to Penelec changing from a net lender in 2003 to a net borrower in 2004 in the money pool with associated companies. The change in funding position resulted from a $51 million repayment to the NUG trust fund in 2004 compared to a $106 million withdrawal from the NUG trust in 2003.
Upon adoption of SFAS 143 in the first quarter of 2003, Penelec recorded an after-tax credit to net income of $1.1 million. The cumulative 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 $1.9 million increase to income, or $1.1 million net of income taxes.
Penelec’s cash requirements in 2004 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 two years, Penelec expects to meet its contractual obligations with cash from operations. Thereafter, Penelec expects to use a combination of cash from operations and funds from the capital markets.
There was no change as of September 30, 2004 and December 31, 2003 in Penelec’s cash and cash equivalents of $36,000.
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Net cash provided from (used for) operating activities during the third quarter and first nine months of 2004 compared with the corresponding periods of 2003, were as follows:
Net cash used for operating activities decreased $51 million in the third quarter of 2004 compared to the same period of 2003 due to a $79 million increase in working capital (primarily from changes in accounts payable, receivables and prepayments) offset by a $50 million voluntary pension contribution. The increase in cash earnings of $23 million is described above under “Results of Operations”. Net cash provided from operating activities increased $54 million in the first nine months of 2004 compared to the same period of 2003 as a result of a $42 million increase in cash earnings and a $63 million increase in working capital (principally changes in accounts payable and receivables) offset by the $50 million pension contribution.
Net cash provided from financing activities increased by $24 million in the third quarter of 2004 from the third quarter of 2003. Net cash provided from financing activities was $79 million for the first nine months of 2004 compared to net cash used for financing activities of $51 million in the first nine months of 2003. Changes in both periods resulted from an increase in short-term borrowings and a decrease in common stock dividends to FirstEnergy, partially offset by a higher level of long-term debt redeemed in 2004.
In March 2004, Penelec completed a receivables financing arrangement providing for borrowings of up to $75 million. The borrowing rate is based on bank commercial paper rates. Penelec is required to pay an annual facility fee of 0.30% on the entire finance limit. The facility was drawn in the third quarter for $55 million and matures on March 29, 2005.
On September 1, 2004, Penelec redeemed at par $100 million principal amount of its subordinated debentures in connection with the concurrent redemption at par of $100 million principal amount of 7.34% Penelec Capital Trust Preferred Securities.
As of September 30, 2004, Penelec had approximately $244 million of short-term indebtedness, including $55 million drawn on its receivables financing arrangement. Penelec has obtained authorization from the SEC to incur short-term debt of up to $250 million (including the utility money pool). Under the terms of its senior note indenture, Penelec is no longer permitted to issue FMBs so long as senior notes are outstanding. Penelec has no restrictions on the issuance of preferred stock.
Penelec has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2004 was 1.28%.
Penelec’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook on all of its securities is stable. On August 26, 2004, S&P stated that a favorable outcome of FirstEnergy’s Ohio Rate Stabilization Plan auction process and a favorable resolution of pending environmental litigation would support a higher ratings outlook, or possibly a higher rating. S&P noted that a ratings upgrade in 2004 does not appear likely because those major issues would most likely not be resolved before the end of 2004. On September 14, 2004, S&P stated that FirstEnergy’s $500 million voluntary contribution to its pension plan was credit neutral.
Net cash used for investing activities totaled $24 million in the third quarter of 2004 compared to $51 million
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provided from investing activities in the third quarter of 2003. Net cash used for investing activities was $98 million in the first nine months of 2004, compared with $76 million provided in the same period of 2003. The increase in cash used for investing activities for both periods reflected decreased net loan repayments from associated companies. The increase for the first nine months of 2004 also resulted from a $51 million repayment to the NUG trust fund in 2004 and a $106 million withdrawal from the NUG trust fund in 2003.
During the last quarter of 2004, capital requirements for property additions are expected to be about $25 million. Penelec has additional requirements of approximately $0.2 million for maturing long-term debt during the remainder of 2004. Those requirements are expected to be satisfied from internal cash and short-term credit arrangements.
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.
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 2004 is summarized in the following table:
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:
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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, 2004.
Included in Penelec’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $54 million as of September 30, 2004 and December 31, 2003. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of September 30, 2004.
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 transmission and distribution systems, which remain regulated. The PPUC authorized Penelec’s rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. Penelec has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as its PLR obligation.
In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Penelec to defer, for future recovery, energy costs in excess of amounts reflected in its capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision also affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. Penelec established a $111 million reserve in 2002 for its PLR deferred energy costs incurred prior to its acquisition by FirstEnergy, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. The reserve increased goodwill by an aggregate net of tax amount of $65 million.
On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Penelec filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Penelec’s restructuring settlement previously approved by the PPUC.
On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 20, 2001 order in its entirety. The PPUC directed Penelec to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day’s notice. In response to that order, Penelec filed supplements to its tariffs to become effective October 24, 2003.
On October 8, 2003, Penelec filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund, and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC’s findings would not impair its rights to recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Penelec for the NUG trust fund refund, denying Penelec’s other clarification requests and granting ARIPPA’s petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Penelec filed an Objection with the Commonwealth Court
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asking that the Court reverse the PPUC’s finding that requires Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis.
On October 27, 2003, one Commonwealth Court judge issued an Order denying Penelec’s Objection without explanation. Due to the vagueness of the Order, Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Penelec, in order to preserve its rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC’s October 2 and October 16 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Penelec’s Objection was intended to be denied on the merits. In addition to these findings, Penelec, in compliance with the PPUC’s Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC’s findings in their Orders.
Penelec purchases a portion of its PLR requirements from FES through a wholesale power sale agreement. The PLR sale is 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 retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Penelec under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Penelec’s exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of Penelec’s unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previously allowed under the PPUC’s order. Penelec is authorized to continue deferring differences between NUG contract costs and current market prices.
Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of Penelec’s regulatory assets are expected to continue to be recovered. Penelec’s regulatory assets were $294 million and $497 million as of September 30, 2004 and December 31, 2003, respectively.
Penelec has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, Penelec’s proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Penelec has accrued liabilities aggregating approximately $26,000 as of September 30, 2004. Penelec accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in Penelec’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy’s service area. On April 5, 2004, the U.S. –Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid’s reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility’s system. The final report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 (see Reliability Initiatives below). FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these
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initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of September 30, 2004 for any expenditures in excess of those actually incurred through that date.
In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and required additional reporting on reliability. The PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order approving the revised reliability benchmark and standards, including revised benchmarks and standards for Penelec. The Order permitted Pennsylvania utilities to file in a separate proceeding to revise the recomputed benchmarks and standards if they have evidence, such as the impact of automated outage management systems, on the accuracy of the PPUC computed reliability indices. Penelec filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards due to their implementation of automated outage management systems following restructuring. No procedural schedule or hearing date has been set for this proceeding. FirstEnergy is unable to predict the outcome of this proceeding.
On January 16, 2004, the PPUC initiated a formal investigation of whether Penelec’s “service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring” in Pennsylvania. Hearings were held in early August 2004. On September 30, 2004, Penelec filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settlement, Penelec agreed to enhance service reliability, performance reporting and communications with customers and together with Met-Ed and Penn, to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. In November 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.
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Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penelec’s normal business operations are pending against Penelec, the most significant of which are described above.
Penelec prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect its financial results. All of Penelec’s assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Penelec’s more significant accounting policies are described below.
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 Penelec is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. 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.
Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management’s intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management’s expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. Penelec continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Penelec enters into commodity contracts which increase the impact of derivative accounting judgments.
Penelec follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class and electricity provided by alternative suppliers.
FirstEnergy’s pension and postretirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. Penelec’s reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy’s merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key
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assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.
In accordance with SFAS 87 and SFAS 106 changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants’ experience.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy’s pension costs in 2003 and in the first nine months of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution ($50 million funded by Penelec) to its pension plan. This contribution will mitigate future funding requirements and significantly reduce the year-end minimum pension liability that currently reduces Penelec’s accumulated other comprehensive income by $42 million.
In accordance with SFAS 144, Penelec periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, Penelec 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).
In accordance with SFAS 143, Penelec recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of Penelec’s current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Penelec used an expected cash flow approach (as discussed in FCON 7 to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes.
In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, Penelec evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is 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 most recent annual review was completed in the third quarter of 2004, with no impairment indicated. The forecasts used in Penelec’s evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on Penelec’s future evaluations of goodwill. In
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the first nine months of 2004, Penelec reduced goodwill by $15 million for pre-merger interest received on an income tax refund and other tax benefits. As of September 30, 2004, Penelec had $884 million of goodwill.
Issued in May 2004, FSP 106-2 provides guidance on accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. The effect of the federal subsidy provided under the Medicare Act on FirstEnergy’s consolidated financial statements is described in Note 4.
In December 2003, the FASB issued a revised interpretation of ARB 51, referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, Penelec adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on Penelec’s consolidated financial statements. See Note 2 – Consolidation for a discussion of variable interest entities.
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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, 2004, there were no changes in the registrants’ internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants’ internal control over financial reporting.
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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 3 and 6 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES
(e) FirstEnergy
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.
ITEM 6. EXHIBITS
(a) Exhibits
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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.
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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 4, 2004
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